WoodMac: Tax Rethink Needed in Sub-Saharan Africa

WoodMac: Tax Rethink Needed in Sub-Saharan Africa
Wood Mackenzie says that revisions to how oil and gas companies are taxed may be needed to unlock sub-Saharan Africa's 48 billion barrels of discovered oil if the current period of low energy prices persists.

Revisions to how oil and gas companies are taxed may be needed to unlock sub-Saharan Africa's 48 billion barrels of already-discovered oil, according to the findings from a new study by consulting firm Wood Mackenzie.

The findings, released on Wednesday to coincide with Cape Town's Africa Oil Week, prompted Wood Mackenzie to assert that the oil price crash has accelerated the need for fiscal adjustments, as sub-Saharan African governments prepare to weather significant reductions in vital tax revenue.

With no increase expected in production volumes, Wood Mackenzie believes that future revisions will need to strike the right risk and reward balance – incentivizing investors to commercialize the continent's vast untapped resource base. 
Wood Mackenzie said the oil price decline has heightened the need for fiscal change, and the firm estimates that governments across the region will take around $50 billion less in hydrocarbon taxes in 2015 as company budgets are forced down by the price drop. 
Martin Kelly, director for sub-Saharan Africa upstream research at Wood Mackenzie, explained:

"Less than 10 percent of the 48 billion of barrels of oil equivalent (boe) discovered in Sub Sahara Africa over the last decade have reached final investment decision (FID).  As a result, there will be little or no increase in production from new developments that offsets the loss of vital hydrocarbon tax earnings. Nigeria alone relies on the oil and gas industry for 70 percent of its revenues."
Ross Millan, a petroleum economist at Wood Mackenzie added:

"Since 2010, almost 20 sub-Saharan countries have revised their fiscal frameworks. Throughout the process, we've seen two common themes emerging: tougher terms in response to previous exploration success and updated hydrocarbon laws to capture current industry trends, such as increasing focus local content, technological advance and new areas of exploration. In addition, increased state equity, greater local company participation and the profit-related production sharing contracts (PSCs) are some of the key changes we've seen widely introduced.
"A number of other nations have also announced their intention to overhaul fiscal terms and some already have legislation making its way through the parliamentary approval process. In many ways the lull in exploration activity and new project sanctions has provided governments with a unique opportunity to overhaul ineffective and potentially outdated fiscal systems before the next wave of investment." 
According to Wood Mackenzie, the percentage of government share in hydrocarbon profits across Sub Saharan African countries (onshore 66.1 percent; shelf 60.5 percent; deepwater 61.6 percent) is higher than the global average (onshore 57.6 percent; shelf 58.3 percent; deepwater 57.8 percent) despite the challenges companies face operating in the region.

"Whilst the region has tremendous resource potential, neighboring countries are in direct competition for international investment and must understand where the next round of fiscal changes could position them against their peers in the eyes of the global upstream industry," Kelly said.
Wood Mackenzie cautions that the decisions taken today will have a huge impact on whether or not African nations can rely on lasting tax revenue streams from oil and gas production to support state budgets in the decades ahead.

"Finding oil is one thing, but getting it to market as a taxable commodity is another. Sub-Saharan Africa has a tremendous opportunity to generate wealth from hydrocarbon resources in the coming years, but in order to do so need to ensure that future fiscal revisions strike the correct balance for investors between risk and reward," Kelly added.

Sub-Saharan Africa has seen some major oil and gas discoveries in recent years. While Nigeria has long served as the region's main source of hydrocarbons, Tullow Oil's TEN cluster of oilfields, offshore Ghana, was found in 2009 and contains gross reserves of approximately 300 million barrels of oil equivalent. The TEN development is on track to produce its first oil in mid-2016.

Meanwhile, on the other side of Africa the Rovuma Basin in Mozambique has been estimated to contain in excess of 30 trillion cubic feet of natural gas.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com


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Philippe Landras | Oct. 29, 2015
In one of my previous comment I stated that the “Majors” privately own must enter in “Joint Ventures” (JV) with local government to access oil or gas production. A little history is important to understand the situation: Early in the 20th century the “Big 7 Sisters” had little or no competition and had total control of the production and paid a “rental” fee. The word “rent” was used; the host country had sovereignty of the oil beneath the land. The oil had no value until one of the “7 Sisters” risked its capital, expert technology, to discover, produce and market crude oil. The host country was the “landlord”, and the “Sister” the “tenant”. These local governments were paid a rent for the acreages of desert. OPEC, which Venezuela was a founding member, big changes came upon the “7 Big Sisters” monopoly? First many new Exploration & Producers (EP) companies came on the scene, competition became feared. The important development is that OPEC took over the management of these assets and the “7 Big Sisters” and others became minority partners. The host government paid the “7 Big Sisters” a percentage of the production. . At first 50% was a royalty payment but became a 49%-51% Joint Venture (JV) the oil companies became minority owner. A partnership involves the sharing of all aspects of the management as well as engineering and construction. The transfer of technology started to become the norm The terms of these capital requirements are very deferent than the rental fee of yester years. Today an “Elephant” grass root project cost 3 billion to 5 billion. This cost includes: the financing, engineering, construction and start up. In Nigeria and many other host nations, the project currency is the Niara the local currency, 60% of the project cost must be spent with or through local Nigerian companies; this includes the local work force. 40% is left for the purchase of the major equipment overseas. Unable to control the political winds of the host government, ExxonMobile and other majors amortize their capital over 5 years or less. The risks make it impossible to amortize over 30 years. The politic involved in setting crude oil index price does not permitted it, the present case Few OPEC members have the means to finance their own projects. In the past these host governments made JVs with major’s oil companies. Is it really in the interest of major oil companies to risk billions of dollars upfront? I do not think so. It appears that buying crude oil on the world market eliminate or control any risks. Keeping a diversified source of crude oil provide the financial security required. The business model of these major oil companies will cause the upstream to diminish, but the downstream to increase in dynamic markets. The world uses 5% of the reserve per year. In 3 years we will have lost 15% of this reserve. A major “Elephant” project takes 5 years from securing a JV, financing etc. all the way to first oil. Should “Elephant” projects not get started for 3 years, the world reserve will have receded 40%. 15% for the first 3 years and 25% waiting for these projects first oil. We are in 2015, the crash started in 2014, what will be the price of crude oil in 2022. Some believe around $200 per barrel. The Saudis want to keep their market share, do they have an interest in helping their competition! This new business model has great consequences. OPEC came to being with the idea of controlling the member’s assets with the “Majors” financing. Few members have been able to grow their wealth to self-finance projects, Saudis Arabia, Kuwait, and Qatar in particular. They have a common particularity, their population is small and their social needs are limited. Iran, Nigeria, Algeria, Indonesia and many others, have the opposite situation. The O&G revenues are spent on social budgetary requirements. Until now the foreign oil companies provided the financing, will this business model continue to feed these potential projects with risky financial schemes. Analyzing the Saudis situation shows a prevailing opinion that a problem will develop in 2 or 3 years is arguable. The wealth of Saudi Arabia resides in the King control the royal family wealth. Presently the Saudi Arabia budget is not balance. In the too distance past, the overseas wealth of the royal family was repatriated to Saudis Arabia. If push comes to shove, oversea Saudis assets, at least some, may be up for sale. The Saudis plan is not a fluke, this first opinion is shallow and will surprise. Same thing with Kuwait and Qatar, Qatar population is not much more than 100K. Most of those living in Qatar are foreigners, Egyptians, Palestinians, with the low manual labor done by Nepalese etc. Will OPEC disintegrate should the Brent index price stays in the $40-$50 for some time. One has to acknowledge the possibility. In the meantime XOM has already shifted resources to the downstream and chemical side of their assets. Exxon is investing in friendlier

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