Guyana’s oil deal is outlier low: government takes just over half

FAST-Compliant Financial Model   Stabroek Narrative Report

Guyana’s first and major oil deal, with ExxonMobil, produces results for the government which are outlier low, an OpenOil financial model reveals. Over the life of the project the government should expect to see from 52% to 54% of profits, compared to well over 60% in a cluster of comparable projects signed in other frontier countries.

The gap could cost the small South American country billions of dollars, as successful drilling continues apace in the Stabroek field, and recoverable reserves figures climb into the billions of barrels.

The relatively low performance of the Stabroek terms, first signed in 1999 and renegotiated in 2016, following the first significant discovery the previous year, holds under a wide variety of market and field size conditions.

There is also a significant possibility, as reserves growth gathers pace, that Exxon and its partners Hess and Nexen could achieve “super profits”, rates of return of over 25% and edging considerably higher under certain conditions, as this profit map of the project shows.

The agreement has become controversial in Guyana in the past year or so and the contract was published by the government at the end of 2017 to allow public scrutiny. The financial model and this accompanying narrative are based on that contract, as well as public statements and media reports giving details of reserves, development lead time and costs.

Even under conservative assumptions, Stabroek will transform Guyana. Government revenues could hit a billion dollars a year by 2024 – more than the entire current government budget.

The 52% Average Effective Tax Rate (also known as “the government take”) is lower than a general rule of thumb of 60% to 80% government take in oil projects, and also from a range of frontier projects in Ghana, Senegal, Papua New Guinea, Mauritania and Guinea, which were comparable at the time of signature. A more detailed description of the comparison methodology is laid out in the Annex to the narrative report.

What is significant here is to understand the role reserves growth scenarios could play in increasing company rates of return.  At the currently stated field size of 450 million barrels in Stabroek, for example, the company does not reach “super profits”, defined here as an Internal Rate of Return (IRR) of 25% or more, until a price point of $75 per barrel for oil. But this field size relates only to the first stage of development of the field now underway, with first oil anticipated for 2020. A second phase is now under active consideration by the companies, with a projected production plateau which could be twice as high as in the first phase. If the amount of oil produced rose only modestly, compared to Exxon’s declared reserves, to 750 million barrels, the superprofit level (25% IRR) could be reached at $50 per barrel – below today’s prices. At a billion barrels, that stage could be reached with prices in the $40s per barrel.

The FAST-compliant financial model and accompanying report are part of OpenOil’s public interesting financial modelling library, part of a practise as commercial and financial analysts to governments and public policy makers.

A second stage of the model will be published in the coming weeks, to incorporate feedback from interested parties, and quantify how revenue streams could play for both investors and the government under a modified fiscal regime.

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Lebanon’s new gas contract: everyone just take a breath!

The news that Lebanon had finally signed a contract for gas exploration in its offshore has set off a flurry of speculation in national and international media. A leading bank in the country produced a report suggesting the government could earn up to $200 billion in revenues from the deal, turn the public deficit into a surplus within five years, and all but eliminate the country’s debt in the long term.

Meanwhile the Gulf News carried a report including quotes from a consultant that domestic consumption of gas could cut fuel bills by $1.5 to $2 billion a year.

While it is not impossible that gas finds could prove transformative, there are so many large uncertainties – in scale, timeline, and even if there is any exploitable resource at all – that there is a serious risk of unrealistic expectations, which could in turn lead to misjudged policy.

OpenOil will publish a full financial model of the deal signed by the Lebanese government with Total, Eni and the Russian firm Novatek in Blocks 4 and 9 in April, as part of our ongoing commitment to create a library of full financial models of oil and mining projects. In the meantime, here are some preliminary observations, based on commercial analysis and an early draft of the model, on some of the predictions made so far.

As far as the Bank Audi predictions – of $400 billion in revenues, of which the government would see half.

  • It seems to be based on a misunderstanding of technical standards for evaluating oil and gas assets. The report speaks in terms of “reserves” of 865 million barrels of oil, and 96 trillion cubic feet of gas. Lebanon currently has no reserves under industry definition, since these need to be confirmed by first drilling, and then a detailed investment plan showing commerciality. Pre-drilling, putative amounts of oil and gas are normally classified as “prospective resources” and considered highly speculative by industry. To put this in context, the ratio between prospective resources and actually produced oil is frequently greater than 10 to 1. So this could be an overestimate of as much as 1,000 percent – assuming any gas is found at all.
  • The agreement is only for two of Lebanon’s ten blocks, whereas the report states the estimates for all Lebanese waters.
  • The chance of drilling converting preliminary estimates from seismic studies into producible oil and gas is known as the “chance of success” (CoS). Industry typically uses a CoS of 10% to 20%, though there may be some reason to place the confidence somewhat higher in this case. So it is far from certain that there is anything producible at all.
  • Bank Audi states that the assumption of turnover is based on current prices. First, this is unstable as the markets are continuously volatile. Second, gas in particular has no global market price so valuation depends on which market it is assumed Lebanese gas would supply.
  • In terms of debt servicing any reasonable time frame for development of the field would not see sizeable production, and therefore revenues, until the late 2020s. The level of discounting then required on future revenue predictions is going to be considerable to assess what the deal is worth in today’s money – “Net Present Value”. Meanwhile, presumably existing debt accumulates compounded interest.

In terms of general economic knock-on – cheaper fuel available to the domestic economy – it requires an entire chain of optimistic assumptions to reach the level of savings discussed, in the $1.5 billion a year range. Production would need to reach nearly a trillion feet a year, all of it allocated domestically, prices the same as now in European markets, and the use of gas to be 50% more efficient in generating power.

To put this in perspective, Eni describes the Zohr field in the Egyptian Mediterranean as a “super giant”, with 25 trillion cubic feet.

Separate to the question of what level of resource may be found, and what extraction costs would be, two other key factors have yet to be addressed, transport infrastructure and sales agreements. Whether pipeline or LNG, for domestic or international use, infrastructure to bring the gas to market will clearly cost billions of dollars, and if there are discoveries there will be a complex series of calculations around what level of production can support what kind of infrastructure. Also, for gas companies typically need to secure baseline sales agreements – “term contracts” – before they begin development, to reduce risk from future volatility and assure a minimum return on capital.

More detailed results will come with the model. But it is essential that a sober view is maintained. Lebanon is several large leaps away from any gas discoveries – which have yet to be made – solving the issue of its public debt, or even providing a “soft landing” for its economy, and no public policy should be made on that basis.

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Running the Numbers: ADB and OpenOil launch report on government modeling

Geneva, 19 October 2017 – The African Development Bank (AfDB) and OpenOil, a Berlin-based financial analysis firm, have jointly produced a new report on how African governments use financial models to manage oil & gas and mining projects. The report was launched at the 13th Annual General Meeting of the Intergovernmental Forum on Mining, Minerals, Metals and Sustainable Development (IGF) in Geneva.

Over 150 experts and representatives from international development institutions, governments, civil society and extractives companies attended the launch, including World Bank, United Nations Environment Programme (UNEP), United Nations Development Programme (UNDP), United Nations Conference on Trade and Development (UNCTAD), Organisation for Economic Co-operation and Development (OECD) as well as mining companies and miners’ associations such as Newmont Mining Corporation, AngloGold Ashanti, Anglo American and International Council on Mining and Metals (ICMM). The joint report was presented by Pietro Toigo of the African Natural Resources Center of AfDB and Olumide Abimbola from OpenOil. “This report is the first of its kind in Africa and we hope that it will stir debate within the continent’s mining sector and contribute to countries getting more out of their mining projects,” they told the participants from governments, bilateral and multilateral organisations, private mining companies, and civil society groups.

The report, Running the Numbers: How African Governments Model Extractive Projects,  analyses the capacity of 19 African resource-rich countries to use financial models, which simulate a simplified version of a real-world project in order to determine their financial benefits to the countries. AfDB and Open Oil conducted a survey of nearly 50 government officials to illustrate not only how widespread use of financial models is, but also how their results are utilised to inform policy, but also how they are used.

“Financial models are essential throughout the life-cycle of extractive projects,” said Johnny West, Director of OpenOil. “They are not just important during the development of the fiscal regime, but also for the negotiation of fiscal terms with companies, for revenue forecasting, and for auditing and tax-gap analysis.”

“This report not only stresses the need for African Governments to make efforts to close the information gap with extractive companies, but also shows where there are capacity gaps and how those gaps could be addressed, calling for development partners to invest further in capacity building.” recognized Modibo Traore, Officer in Charge of the African Natural Resource Center of the AfDB,

African countries also face a substantial gap in access to data that are key inputs for financial models, with the largest gaps seen in assessing information on capital costs and operating costs of projects.

In addition to the need for governments to build in-house financial modelling capacity, the report suggests that governments need to improve internal business processes and address the large gap that the report shows exist between information available to different agencies, departments and ministries.

“This study forms a crucial part of the Center’s support to African countries in realising the full potential of their natural resources”, said Modibo Traore, “How are countries supposed to enter, for example, negotiations with extraction companies -who all use financial models- if the government has not used the latest and best models to calculate what a potential project is worth?” added Pietro Toigo, macroeconomist at the African Natural Resources Center.

The report also encourages development partners to make capacity building in financial modeling a more significant part of their support to the management of extractive resources. Those partners who already do are encouraged to not just supply financial models as part of isolated technical assistance, but to also invest in equipping government officials with skills to create and use models.

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Yaoure tax holiday costs Cote d’Ivoire $120 million

The publication of the financial model of Yaoure gold mine shows what can be done: both in the tricky area of what tax incentives offer, and in terms of building government analytical capacity.

OpenOil, with support from the German Corporation for International Cooperation (GIZ), worked with colleagues from Cote d’Ivoire’s Ministry of Mines to build the financial model and accompanying report. We believe this is the first time that officials themselves have substantially led the development of financial analysis.

The results are revealing at a couple of levels. Cote d’Ivoire has had a policy of a holiday on Corporate Income Tax in place for at least 20 years. During that time, many people have had much to say about the policy: successive governments have defended it as necessary, those opposed have denounced it for giving too much away – and sometimes effectively accused those who maintain the policy of having ulterior motives.

First of all, nobody had ever costed the tax holiday, and the model solves that.

Against a base scenario (explained in detail in the report), over $120 million of tax revenues will be foregone in the Yaoure gold mine in its first five years of production. That’s equivalent to more than a quarter of government revenues from the entire sector in 2015.

But the model goes a stage further. Because even knowing how much the incentive cost does not mean you can prove it was unnecessary. The case that if the holiday was not on offer the investor would walk has to be addressed.

This is where financial analysis comes into its own. The whole point of a government, or a CSO, building a financial model is to assess the business position of the investor – so as to know what constitutes a “fair” deal, what revenues governments can expect, and so on. This is done through estimating the rate of return, both before and after tax.

So, in the base scenario, the company (originally Amara, but Amara was then sold to Perseus Mining in Australia), earned nearly 30% rate of return after tax. Investors adjust for “country risk” and Cote d’Ivoire would certainly carry some of that. Nevertheless, it is a handsome return by any standard.

But that is with the tax holiday. What the Yaoure model then answers is: what would the investor’s rate of return be if the tax holiday were cancelled? And the answer is: a still fairly handsome post-tax Internal Rate of Return of 25%. This builds a strong case that the tax holiday is, in the case of the Yaoure mine, not necessary to provide an attractive enough incentive.

In other words it is money left on the table.

It does not follow, of course, that that will be the case in every mine. Elsewhere the economics could be different. Or not. What this project has done is deliver a tool to the government which enables it to run this kind of analysis, project by project, and lead an informed discussion about tax incentives in the country.

It is possible the results will need revision. We have based this model on data published by the company itself, but mainly in 2014 (A publication in 2016 was not comprehensive enough in an internally consistent manner to be able to build a model off). Costs and prices could both require adjustment which could change the overall numbers on the tax holiday question.

It is unlikely, though, that the numbers would change so much as to alter the basic conclusion – that the tax holiday at the Yaoure gold mine seems unnecessary. And if it did, it is the publication of the model which will have triggered the release of better data proving that case. Just as that better data could be easily slotted into this existing model.

The government in Abidjan is now considering how to deploy financial analysis more broadly. And maybe to require companies bidding for licenses to “show the model”, just as they are required to do with other documents.

This kind of financial modeling is available, and within the technical grasp of any government which would like to develop it. As the results from this one mine alone show, billions of dollars could be in play.

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Where are your country’s oil projects on the “Climate Change Supply Curve”?

The latest report from Carbon Tracker Initiative, a non-profit analysis house in London, suggest that up to a third of currently planned oil and gas projects may now never go ahead because of climate change policy.

In “2D of Separation”, CTI presents the potential risks to shareholders and investors in the world’s largest fossil fuel companies of “stranded assets”: the idea that if world leaders do what they said they would in the Paris Climate Change agreement, fossil fuel production will tail off. And that in turn means that plans for investment in new projects are riskier. And that in turn means companies who invest in new projects that would produce more carbon than be accommodated in the world’s carbon budget risk wasting their shareholders money.

We know that companies have been factoring in this risk of stranded asset for many years now. Global majors such as BP, Shell, Total and Chevron have been applying carbon prices internally to determine which potential projects are most at risk. The question is: who is going to do the same for the many countries around the world whose economies and public finance depend on fossil fuel production?

There are lots of factors in play, of course, price being the main one. New investment has taken a hit since the oil price crash of 2014, rebounding a little as the US shale industry has figured out how to cut costs and present more “agile” supply to the market. And there is no certainty that either policy or the ever dropping costs of green energy will guarantee that the commitments made by governments in the Paris Agreement will be honoured.

Nevertheless, if the Kashagan oil field in Kazakhstan gets stranded, stranding any investment by Shell, the government of Kazakhstan will see its benefits from the project stranded. The same with ExxonMobil’s investment in the Bonga field in Nigeria, or Oil Search’s potential investment in Papua New Guinea. All around the world governments are making plans for economic growth and revenues to Treasury which are at risk, and there is little sign that they are receiving professional advice to help them plan for that. The case is even more pronounced with LNG, presenting risk to governments like Mozambique and Tanzania, which are making plans on the basis of vast new offshore projects.

And it is not just that some projects may not go ahead. There will be other projects where carbon budget considerations make the project more marginal but potentially viable – if the companies can convince countries to restructure terms. Companies could propose deals which maximised revenues to them in the short term, offering governments a larger share of revenues as the project progresses, some time down the road. But if governments are not aware of the overall business environment, what happens if by the time the government’s higher share kicks in, the whole game has moved on? That high return in the future will never, in fact, arrive.

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