I have developed my interest in the field of the GEOPOLITICS of ENERGY (OIL & GAS) in the MIDDLE EAST & NORTH AFRICA (MENA) over the course of several years. I help gathering timely intelligence and developing scenarios in relation to energy issues in the MENA.
The analysis “A Snapshot of South Sudan’s Oil Sector,” has been published by the Oil and Gas Council, the leading network of energy executives in the world. This analysis is related to Africa Assembly 2018, which is the largest African O&G finance and investment event. The Oil and Gas Council will organize Africa Assembly 2018 on June 5-6 in Paris, France.
June 1, 2018
London, United Kingdom
According to BP Statistical Review 2007, at the end of 2016 South Sudan had 3.5 billion barrels of proven crude oil reserves, i.e., 0.2% of the world’s proven crude oil reserves. However, South Sudan, which got its independence from Sudan in July 2011, because of several problems, such as the lack of independent export routes, border disputes with Sudan, and since December 2013 an ongoing civil war, has not been able until now to consistently develop its oil industry; on the contrary, its oil production is currently declining. As a matter of fact, in July 2011, South Sudan was producing about 325,000 b/d, while production is now about 135,000 b/d. In addition to the three above-mentioned main problems, part of the reason for the oil-production decline is also linked to the mature status of the oilfields in South Sudan’s Unity State and Upper Nile State.
All the countries that rely consistently on natural resources always face difficult challenges, and they must constantly find a balance between, on the one side, their need to attract investment to explore and develop natural resources, and, on the other side, their need to ensure that the government receives a fair share of the countries’ resource wealth. To continue to develop its oil sector, South Sudan must bring in both technical expertise and financial resources, but, as a result of the above-mentioned problems, it’s not easy to find additional investors. South Sudan’s petroleum fiscal framework is based on production sharing contracts (P.S.C.s), and the country is currently developing a model P.S.C. Moreover, South Sudan must pass additional legislation concerning its hydrocarbons sector.
THE HISTORICAL CONTEXT AND THE PRESENT PROBLEMS
That the economic development of South Sudan would not be simple was clear well ahead of the July 2011 independence from Sudan. History tells us that before the independence from the United Kingdom in 1956 of what is today’s Sudan and South Sudan, unrest was already emerging to the surface in southern Sudan. After the 1956 independence, southern rebel groups started to fight against the central government in Khartoum for the independence of southern Sudan. Two civil wars ensued: The First Sudanese Civil War from 1955 to 1972 and the Second Sudanese Civil Warfrom 1983 to 2005. The second civil war ended with the Comprehensive Peace Agreement (C.P.A.) between the government and the southern forces. The C.P.A. established a timeframe for organizing a referendum for the independence of southern Sudan. The referendum was held in January 2011, and then South Sudan became independent in July 2011.
Despite the independence, problems for South Sudan did not stop. In particular, for South Sudan the three main problems are the lack of independent export routes, border disputes with Sudan, and since December 2013 an ongoing civil war. First, South Sudan, which is a landlocked country, is obliged to export its crude oil via pipeline through Sudan, which requires the payment of high transit fees—oil goes to Sudan’s refineries and to Port Sudan on the Red Sea from where crude oil is shipped almost exclusively to China. Some years ago, it was proposed the idea of constructing a pipeline to Kenya or Djibouti (the latter option via Ethiopia). However, because of South Sudan’s present declining crude oil production, it’s difficult to build this second pipeline if there is not a guaranteed amount of crude oil to ship through the pipeline.
In this regard, a few months after the independence, South Sudan declared in January 2012 that it would shut down its production because of disagreement with Sudan about oil transit fees—Sudan had started to confiscate the oil passing through its territory. Later, the South Sudan’s army together with Sudanese opposition forces occupied the Heglig oilfield for about a week before Sudan took it back. This oilfield is administratively located in Sudan, but it straddles the border between Sudan and South Sudan. Because the occupying forces had destroyed part of the oilfield infrastructure, Sudan’s oil production was temporarily reduced by 50%. Only in November 2012, was it possible to find a solution defining oil transit fees and a compensation measure for the lost production. Oil production restarted only in April 2013.
However, the problem of the transit/debt repayment fee is a big problem for South Sudan. According to the agreement in 2012, South Sudan was obliged to pay for 3.5 years to Sudan for each barrel of oil shipped through the Sudanese territory $15 as debt repayment and $9.1 as transit fee for the oil produced in Upper Nile State (Block 3 and Block 7) and $11 for the oil produced in Unity State (Block 2 and Block 5A). With such a high amount of fees paid to Sudan, for South Sudan low oil prices might really eat away at all the profitability relating to its oil production activity. On top of this, it’s important to underline that South Sudan’s two main crude oil blends, the Dar blend (25.0 A.P.I. degrees and sulfur content of 0.11%) and the Nile blend (33.9 A.P.I. degrees and sulfur content of 0.06%) trade at a discount to Brent. While the Nile blend trades at a small discount, the Dar blend is strongly discounted because it trades at $7 to $10 less than the Brent’s price.
After a year of negotiations (South Sudan wanted to change the terms of the agreement), at the end of 2016, Sudan and South Sudan extended the fee agreement for three other years. The agreement between the two parties has not been released publicly, but according to some ministerial sources, it appears that if oil prices are below $30 per barrel, South Sudan will pay only the regular transit fees (a $9.1 transit fee for the oil produced in Upper Nile State and a $11 transit fee for the oil produced in Unity State). But if prices reach $61 or more, South Sudan must pay, in addition to the standard transit fee, also the full $15 debt repayment fee. Instead, between the two thresholds, South Sudan must pay a reduced debt repayment fee according to a sliding scale.
Second, the border between Sudan and South Sudan at certain locations, such as around the Abyei area and the Heglig oilfield, is disputed. The reason is that in those areas oil fields straddle the border between Sudan and South Sudan. The Abyei Area is an area of 4,072 square miles. The 2004 Protocol on the Resolution of the Abyei Conflict accorded "special administrative status" to the area. According to the protocol, this area was declared, on an interim basis, to be at the same time part of both Sudan and South Sudan. Instead, Heglig is a small town on the border between Sudan’s South Kordofan State and South Sudan’s Unity State. Both countries claim the Heglig area, but it’s presently administered by Sudan.
Third, the ongoing civil war, which started in December 2013, between forces of the government (Sudan People's Liberation Movement) and opposition forces (Sudan People's Liberation Movement in Opposition). Several ceasefires have been reached since January 2014, but nothing has resulted in a definitive and permanent agreement. In specific, the Compromise Peace Agreement (C.P.A.), signed in August 2015, seemed to be the right one, but then in July 2016 fighting started again. Currently, rebel in-fighting is a major part of the fighting. According to the United Nations, in 2017 out of a population of 12 million, there were 1.5 million people who had fled to neighboring countries (primarily to Kenya, Sudan, and Uganda) and more than 2.1 million of people who were internally displaced. In addition, fighting occurs in agricultural lands as well, and, as a result, this year, also during harvest time in January, more than 5.0 million people did not have sufficient food to eat. So, it’s almost sure that in the summer of 2018 half of the country’s population will be on the brink of famine.
Recently, the United States and the international community have increased theirs sanctions on South Sudan as a response to the present chaotic destabilization in the African country. In February 2018, the United States announced that it was implementing restrictions on the export of defense articles and defense services into South Sudan. And then, in March 2018, the United States imposed sanctions on 15 South Sudanese oil operators because according to the United States money from these oil companies was used for purchasing weapons and funding irregular militias, which undermine the peace, security, and the stability of the country.
OIL IMPORTANCE FOR SOUTH SUDAN’S ECONOMY
For many developing countries that export raw commodities, commodities play a substantial role in their economy, and South Sudan does not escape this condition, and it is one of the most oil-dependent countries in the world. In fact, South Sudan has an economy practically exclusively relying on the export of crude oil. Harvard University’s Atlas of Economic Complexity shows that in 2016, 98.71% of South Sudan’s exports (for an amount of $1.39 billion) was categorized as “petroleum oils, crude.” The remaining, but almost negligible, export included other oil seeds and oleaginous fruits, dried leguminous vegetables, flour and meals of oil seeds or oleaginous fruits, and peanuts; vessels and other floating structures for breaking up (scrapping); ferrous waste and scrap, and re-melting scrap ingots of iron or steel; commodities not specified according to kind; and cotton, not carded or combed. And, in the previous years after the independence, the percentage of crude oil exports was more than 99%.
At the same time, oil accounts for 98% of the government’s annual operating budget and 60% of the G.D.P. These numbers tell that, apart from the petroleum sector, South Sudan’s economy is a subsistence economy based on agriculture and humanitarian assistance. In practice, for an economy so strongly dependent upon the export of a single raw commodity, a reduction in production and/or a decline in the price of the exported commodity has always a devastating impact. And, this is what happened between 2014 and 2017, when in South Sudan oil production declined, and oil prices were low on the international markets.
THE OIL COMPANIES IN SOUTH SUDAN
Most of South Sudan’s proven oil reserves are in the Mugland Basin and in the Melut Basin, which straddle the border between Sudan and South Sudan. However, as in many other African countries, hydrocarbons exploration has been quite limited, and a large part of South Sudan’s territory is still unexplored for oil and gas—additional exploration is required, but it needs high expertise and important financial resources because of the difficult geographic conditions of part of the territory (for instance, the Sudd). As of today, the associated natural gas is primarily flared or reinjected—the country has 3 trillion cubic feet of proven natural gas reserves.
In South Sudan there are currently three main oil consortia:
1 — Greater Pioneer Operating Company (G.P.O.C.), which comprises China’s C.N.P.C (40%), Malaysia’s Petronas (30%), India’s O.N.G.C. (25%), and South Sudan’s Nilepet (5%).
2 — Dar Petroleum Operating Company (D.P.O.C.), which comprises C.N.P.C. (41%), Petronas (40%), Nilepet (8%), China’s Sinopec (6%), and Egypt’s Tri-Ocean Energy (5%)
3 — Sudd Petroleum Operating Company (S.P.O.C.), which comprises Petronas (67.9%), O.N.G.C. (24.1%), and Nilepet (8%)
A simple look at the companies involved shows that most of the investors in South Sudan’s oil sector are primarily Asian oil companies. This is due to the difficulties in the 1980s and 1990s between Sudan’s government (when South Sudan was still part of Sudan) and the United States. These difficulties forced Western oil companies (for instance, U.S. Chevron, Canada’s Talisman, and Austria’s O.M.V.) out of Sudan, so the Asian companies filled the vacuum left by the Western companies.
G.P.O.C. is the operator at Block 1 (Unity field, Toma field, and Munga field), Block 2 (Heglig field and Bamboo field), and Block 4 (Diffra field and Neem field). D.P.O.C. is the operator at Block 3 and Block 7 (Palogue field and Adar-Yale field). S.P.O.C. is the operator at Block 5 (Mala field and Thar Jath field). G.P.O.C. produces exclusively the Nile blend, while D.P.O.C. and S.P.O.C. produce the Dar blend.
In any case, these Asian companies are not presently investing in South Sudan as much as they should. Without consistent investments in both enhanced oil recovery (E.O.R.) and in new exploratory activity, South Sudan’s production could become less than 100,000 b/d in just a few years. According to the World Bank, on current reserve estimates, oil production is expected to reduce progressively in the coming years and to become insignificant by 2035. Good news is that in March 2018, Petronas extended its contract to explore and produce oil and gas in Block 3 and Block 7 as part of the D.P.O.C. consortium. At the same time, Petronas committed to invest in the resumption of production at the conflict-hit Unity field (Block 1A), which, together with other oil fields, had been shut down in 2013 because of fighting activities in the area.
It’s important to underline that the D.P.O.C. consortium is the only one of the three main operating consortia in South Sudan that continued with its oil production at its fields while fighting made the other two production areas, the S.P.O.C. and G.P.O.C., inaccessible to the operators. Some months ago, the government of South Sudan conducted security surveys in relation to the S.P.O.C. and G.P.O.C., areas, and then it declared that they are once again safe for oil operations. The improved conditions on the two areas was verified by a security risk assessment conducted by a private sector contractor.
SOUTH SUDAN’S PETROLEUM FISCAL REGIME
In South Sudan, the Ministry of Petroleum and Mining is the institution managing the petroleum sector. Instead, the National Petroleum and Gas Commission (N.P.G.C.) is the main policymaking and supervisory body. Among its main tasks there is to approve the petroleum agreements on behalf of the government. The Nile Petroleum Corporation (Nilepet) is South Sudan’s national oil company. Until today, Nilepet has had a limited role in the on-the-ground oil operations because of its limited technical expertise and limited financial resources. Nilepet has very small stakes in the operating consortia.
There are three main legal documents that define the structure of South Sudan’s petroleum fiscal framework: South Sudan’s Transitional Constitution, the 2012 Petroleum Act, and the 2013 Petroleum Revenue Management Act. In 2012, South Sudan passed the 2012 Petroleum Act, which defines in a general manner South Sudan’s petroleum fiscal regime. Additional legislation must be enacted—a model production sharing contract (P.S.C.) is under development. South Sudan’s petroleum fiscal system is based on P.S.C.s. Many oil blocks were already allocated by the Sudan Government before South Sudan became independent in July 2011.
Below there is a list of the main, but still very generic, features of the 2012 Petroleum Act:
—Art. 7 (Principles and Objectives) 1affirms that petroleum existing in its natural state in the subsoil of the territory of South Sudan shall be owned by the people of South Sudan and managed on their behalf by the government.
—Art. 17 (Reconnaissance Licenses) 2 affirms that a reconnaissance license grants a non-exclusive right to undertake data collection (including seismic surveying), processing, interpretation and evaluation of petroleum data in the area stipulated in the license.
—Art. 17 (Reconnaissance Licenses) 3 affirms that if deemed necessary to establish a commercial basis for an exploration survey in a block or portion of a block, the Ministry of Petroleum and Mining shall announce an open, transparent, non-discriminatory and competitive public tender for an exclusive reconnaissance license in an area not already covered by a reconnaissance license.
—Art. 18 (Tendering Procedure and Qualification Requirements) 1, affirms that exploration, development, and production of petroleum shall be carried out in accordance with the terms of petroleum agreements, the 2012 Petroleum Act, and any other applicable law.
—Art. 18 (Tendering Procedure and Qualification Requirements) 2 affirms that petroleum agreements shall be entered after an open, transparent, non-discriminatory and competitive tender process conducted in accordance with applicable law governing public procurement.
—Art. 20 (Incorporation and Organization Requirements) 1 affirms that an entity entering into a petroleum agreement shall be incorporated and registered as a company in South Sudan in accordance with the applicable law. This company shall be incorporated as a single-purpose company exclusively for petroleum activities in South Sudan.
—Art. 25 (Term) 1 affirms that a petroleum agreement may be entered into for a period not exceeding 25 years.
—Art. 26 (Exploration Period) 1 affirms that petroleum agreements shall provide for an exploration period not exceeding six years from the effective date of the agreement.
—Art. 26 (Exploration Period) 2 affirms that the exploration period shall consist of a first commitment period and up to two optional commitment periods as determined in the petroleum agreement.
—Art. 33 (Restrictions on Flaring and Venting) 1,2, and 3 affirm that gas flaring or venting is prohibited, unless specifically authorized or in the event of an emergency. Investors are therefore obliged to invest in necessary facilities in order to utilize any gas they produce.
—Art. 68 (Fees) 1 affirms that a contractor shall pay surface rental fee for the contract area retained under a petroleum agreement as prescribed in the regulations.
—Art. 69 (Royalties and Bonuses) affirms that a contractor shall pay such bonuses or royalties as may be prescribed in regulations or as agreed in a petroleum agreement.
—Art. 70 (Taxes and Customs) affirms that a person conducting petroleum activities in South Sudan shall pay taxes and customs duties in accordance with the applicable law.
—Art. 71 (Production Sharing in Petroleum Agreements) affirms that production sharing shall be as agreed in a petroleum agreement. The Ministry of Petroleum and Mining shall develop a model petroleum agreement in cooperation with the Ministry of Finance and Economic Planning.
Presently, there are no ring-fencing rules in South Sudan. The corporate income tax (C.I.T.) is variable according to the magnitude of the investor’s business. If the business has a turnover of up to 1 million South Sudanese pounds, of up to 75 million South Sudanese pounds, or of 75 million South Sudanese pounds or more, the C.I.T. tax rate will be 10%, 20%, and 25%, respectively. These rates apply to income deriving from oil and gas operations. Taxable income consists of worldwide income for resident companies minus the allowed deductions. For companies that are not resident in South Sudan, taxable income consists of only the profits sourced in South Sudan minus the allowed deductions.
The incurred exploration costs are deductible over the useful life of the asset. The deduction is based on the actual costs incurred, the units extracted, and the estimated total extractable units. The incurred losses can be carried forward for five years, but carryback is not available. A loss from oil and gas operations can be offset against any profits available during the successive five-year period.
The Investment Promotion Act provides for various tax incentives, including capital allowances ranging from 20% to 100% of eligible expenditure, deductible annual allowances ranging from 20% to 40% and depreciation allowances ranging from 8% to 10%. A foreign tax credit is granted to any resident company paying foreign taxes on income from business activities outside South Sudan.
The analysis “Algeria’s and Libya’s Petroleum Fiscal Frameworks,” has been published by the Oil and Gas Council, the leading network of energy executives in the world. This analysis is related to Africa Assembly 2018, which is the largest African O&G finance and investment event. The Oil and Gas Council will organize Africa Assembly 2018 on June 5-6 in Paris, France.
May 16, 2018
London, United Kingdom
Algeria and Libya are two of the world’s most important petroleum-producing countries. According to BP Statistical Review of World Energy 2017, Algeria owns 12.2 billion barrels of proven oil reserves (0.7% of the world’s total) and 4.5 trillion cubic meters of proven natural gas reserves (2.4% of the world’s total, 11thposition in the ranking), while Libya owns 48.4 billion barrels of proven oil reserves (2.8% of the world’s total, 9th position in the ranking) and 1.5 trillion cubic meters of proven natural gas reserves (0.8% of the world’s total). However, it’s worth noting that, as of today, Algeria and Libya have still large swathes of territory completely unexplored for hydrocarbons.
Algeria with an annual production of 91.3 billion cubic meters is the leading natural gas producer in Africa, while Libya with 10.1 billion cubic meters is the fourth. With reference to crude oil production, recent data show that Algeria is currently producing about 1.5 million barrels per day (in 2007, its production was close to 2.0 million barrels per day), while Libya, the holder of Africa’s largest proven crude oil reserves, is currently producing about 1.0 million barrels per day (in 2007, its production was more than 1.8 million barrels per day). The main export market for the hydrocarbons of both countries is Europe.
For both Algeria and Libya, hydrocarbons have long been the backbone of the economy. In specific, according to the International Monetary Fund (I.M.F.), in Algeria, hydrocarbons account for about 30% of the G.D.P., 60% of government revenues, and almost 95% of export earnings. In Libya, because of the ongoing civil war, it’s difficult to have a reliable evaluation. In any case, in Libya, in 2012, i.e., after the demise of Gaddafi’s regime and before the beginning of the Second Libyan Civil War (2014-present), oil and gas accounted for 60% of the G.D.P., almost 96% of government revenues, and 98% of export earnings.
It’s clear from the above data that these two countries share a similar economic structure although Algeria has a more diversified G.D.P. composition than Libya has. Algeria has a preponderant role as a natural gas exporter, while Libya has an analogous role in relation to crude oil. What is interesting is that, in order to improve the development of their respective petroleum (oil and gas) sector, both countries will need to modify their petroleum fiscal frameworks because of the changed petroleum fiscal landscape at the global level. Of course, amending the petroleum fiscal framework is presently secondary in either country to solving its respective present political challenges.
At the political level, Algeria is currently facing important challenges primarily linked to the tough economic conditions (the reduction in oil prices is the main culprit), the complicated presidential election scheduled for May 2019, and the terroristic menace originating from Algeria’s neighboring countries. Despite the increase in the price of oil that has occurred over the last few months, the Algerian government has little room for maneuver because of its limited financial resources, and it faces now more difficulties in economically appeasing the demonstrators currently carrying out strikes across the country as it had done in the past. In fact, in the past, the country used to avert unrest by redistributing its oil revenues.
For Libya, because of the Second Libyan Civil War, the present conditions are much more complicated. The country is at the mercy of the conflict among rival factions seeking control over the territory and the oil reserves. Presently, there are two main factions: the first one is the Government of National Accord, which is supported by the United Nations and controls the Tripoli area and an area of southwestern territory along the border with Algeria, and the second one is the Tobruk-led government, which controls all central and eastern Libya and has the loyalty of the Libyan National Army under the command of General Khalifa Haftar.
THE PREMISE: A CHANGING PETROLUEM FISCAL LANDSCAPE
The main problem with the petroleum contracts is linked to one of their principal characteristics, i.e., their long duration; many times, three decades is quite a normal duration. And, during these decades, the economic profitability based on the initial contractual terms may change consistently. The petroleum business is subject to price cycles linked to several factors—sometimes real boom-bust cycles. So, the best approach when drafting a petroleum contract is to provide it with real flexibility capable of withstanding a different economic landscape. In other words, flexibility that is not based on purely maintaining the status quo present at the time of the signature (for instance, thanks to a strict stabilization clause), but that is based on maintaining a correct equilibrium between the involved parties (for instance, thanks to an equilibrium or outcome-based clause).
In other words, the goal must be to ‘account for’ in a fair and equitable manner and not just ‘take into account’ the different economic conditions. However, this is easier said than done. On top of this, an additional hurdle is that when drafting a petroleum contract, the involved actors behaviorally give a lot more attention to the economic conditions present at the time of the signature. This tendency is the normal trend. The problem is that the economic conditions present at the time of the signature might radically change in just few months. For example, in June 2014, the price of a barrel of oil (Europe Brent crude spot price) was about $115, while in December 2014, i.e., six months later, the price was $65 (a 43% decline).
At the end of the 1990s and beginning of 2000s, the price of a barrel of oil sustained an upward trend. Chindia, i.e., China and India, increased year after year its oil consumption, and the U.S. had still to begin its fracking operations. So, the governments of oil-producing countries started to engage in revising the substantial contractual terms that were the foundations on which the international petroleum companies had based their decisions to sign the petroleum contracts. As a result, relevant changes occurred especially when originally the contracts had been signed in times of low oil prices (for example, in those 15 years between 1985 and 1999).
Presently, after the price decline that started in June 2014, the petroleum fiscal frameworks and the relating contracts of several countries have been recently incapable of attracting a reasonable number of international oil companies (I.O.C.s). So, some of these countries are thinking of amending their fiscal frameworks and contracts—see, for example, the recent changes in Iraq. However, at the time of this writing, the price of oil has increased for the past ten months because of politically motivated production restriction, increased demand, reduced investment in the past years, and geopolitical tensions (for instance, in Venezuela and Iran).
ALGERIA’S PETROLEUM FISCAL FRAMEWORK
Algeria became independent from France in 1962, but some relevant hydrocarbon discoveries had already occurred in the 1950s. In fact, in 1956 were discovered the Hassi Messaoud and the Hassi R’mel oil fields—still today, the country’s two largest oil fields. Then, in 1963, Algeria established Sonatrach, its national petroleum company. At the beginning of its petroleum operations, Algeria’s petroleum legal regime was based on petroleum concessions, which were released by the French authorities. Some years later, in 1970, Algeria began to expropriate some foreign petroleum companies, and, by the end of the year, all the assets of the non-French petroleum companies present in Algeria had been nationalized.
Then, the following year, the Algerian government nationalized a 51% stake in each of the concessions still managed by the French petroleum companies. At the same time, the government nationalized completely the gas sector and the oil and gas pipelines companies. The result was that, in just few years, the petroleum sector was almost completely controlled by the Algerian government. On top of this, in 1980, also France’s Total was obliged to exit the market when the government refused to extend the association agreements with the company. Technically, the petroleum sector was not completely closed to the I.O.C.s, but the terms were so harsh that the I.O.C.s were not much interested any longer into investing in Algeria.
After this last change, some problems materialized quite soon because in those years the oil prices declined and because Sonatrach did not really have the technological expertise to develop a petroleum sector that at that time started to have some mature fields requiring top-notch petroleum skills. Understanding these difficulties, in 1986, Algeria passed a new hydrocarbon law, Law No. 86-14, which introduced the production sharing contracts (P.S.C.s) and risk service contracts in Algeria. The idea was to relax the offered fiscal terms with the specific goal of attracting again the technologically savvy I.O.C.s to Algeria. The problem was that the offered conditions were not sufficiently good to lure the I.O.C.s back to Algeria.
However, in 1991, when the Parliament passed some amendments to Law No. 86-14, Algeria was able to attract one more time the I.O.C.s back to Algeria. The amendments concerned improved fiscal terms and the general conditions relating to the investment operations (the possibility of benefiting from international arbitration was an essential element). This move was successful because in the 1990s I.O.C.s coming from very different geographic areas returned to invest in Algeria in partnership with Sonatrach, which maintained a minimum 51% stake in all the upstream projects.
Then, in April 2005, Algeria introduced Law No. 05-07, whose goal was to modify the oil and gas sector framework. It was created al Naft, which is the body responsible for the organization of the licensing rounds and the award of the contracts, and the Hydrocarbon Regulatory Authority, which is responsible for technical matters. This law reintroduced in Algeria tax and royalty petroleum agreements (concessions) and blocked with reference to future agreements the application of both the P.S.C.s and the risk service contracts. According to this law, the I.O.C.s were supposed to pay a proportional royalty linked to the location and the production of a field and to pay income tax based on a sliding scale increasing with the increase in the hydrocarbons production. It’s worth noting that, despite the enactment of Law No. 05-07, the P.S.C.s entered by Algeria under Law No. 86-14 were still valid—in other words, the new law did not act retroactively invalidating those contracts.
In addition, Law No. 05-07 abrogated the necessary requirement that Sonatrach had a 51% stake in all the upstream projects. However, this abrogation lasted for just a year because, in July 2006, Order No. 06-10 reintroduced Sonatrach’s mandatory 51% stake. In practice, the risk of the exploratory phase in Algeria is all on the I.O.C.s, but then, when there is a commercially viable discovery, Sonatrach must get at least a 51% stake. The order also introduced retroactive taxation concerning all the P.S.C.s executed before Law No. 05-07, and it introduced in relation to contracts signed under Law No. 86-14, a windfall profits tax applied at rates ranging from 5% to 50% according to the production level when the arithmetic price of oil exceeds $30 a barrel.
Then, in February 2013, Law. 13-01 introduced some incentives for the development of unconventional oil and gas. According to this law, the taxation is now based on profit and not on total revenue. At the same time, with reference to the unconventional resources, this law lowered the tax rates and permitted a longer exploration phase (11 years for the unconventional resources versus 7 years for the conventional resources) and longer operating/production periods (30 years and 40 years for unconventional liquids and gaseous hydrocarbons, respectively, versus 25 years and 30 years for conventional liquids and gaseous hydrocarbons, respectively).
As of today, in Algeria exploration and/or exploitation activities must follow the signature of a tax and royalty petroleum agreement, i.e., a concession. Al Naft’s selection of a contracting party is done via a tender procedure, although the Minister for Hydrocarbons may opt for a direct agreement with a specific contractor. The Algerian state has the right to ownership over discovered or undiscovered natural resources located on the soil or subsoil of the national territory. Sonatrach still has have in any agreement a participation stake of at least 51%; a joint operating agreement signed by Sonatrach and its partners (national or foreigner partners) is attached to the agreement. It’s important to underline that all the foreign contracting parties to an agreement must establish an Algerian branch.
With reference to the taxation concerning petroleum agreements signed under Law No. 05-07, as amended, hydrocarbons areas are divided among four different zones, i.e., Zone A, Zone B, Zone C, and Zone D. Taxation is based on four separate components: the surface area tax, the royalty tax, the petroleum income tax, and the additional profits tax. However, each zone has a different taxation level. The surface area tax, equal to the product of the surface of the contractual area and a specific price per square kilometer, depends primarily on the tax zone and on the type of activity carried out. The surface area tax is a non-deductible charge from the tax base for the calculation of other different taxes. This surface area tax is considered for the determination of the rate that is used for determining the petroleum income tax.
The royalty is a percentage of the ‘value of production minus transport costs’ calculated on a deposit by deposit basis. Its value is 5.5% to 20%. The different percentages depend on the level of production and on the specific zone. No matter what the production is, unconventional hydrocarbons have all a 5% rate. The royalty is a deductible charge from the tax base for the calculation of the petroleum income tax and of the additional profits tax.
The petroleum income tax is also determined on a deposit by deposit basis. Its rate is linked to the profitability of the investment. It has a minimum rate of 10% to 30% and a maximum rate of 40% to 70% depending on whether the deposit is conventional, unconventional, or geologically complex. Petroleum income, determined on a deposit by deposit basis, is defined as the value of the production minus the following deductions: the royalty, the annual investment tranches for the development with their uplift values, the annual investment tranches for research with their uplift values, the abandonment and/or restoration costs, the training costs, the costs relating to the gas reinjected into the deposit. The petroleum income tax is a deductible charge from the tax base for the calculation of the additional profits tax.
The additional profits tax is applied to the consolidated profit of all the oil activities carried out by the investors in Algeria. It’s due by all the entities in an exploration or production contract, and it is based on the annual profits after the petroleum income tax. The royalty, the petroleum income tax, the depreciation, the reserves for abandonment or restoration costs are all deducted for the calculation of the taxable basis. There are two applicable rates: 30% and 15% (the latter rate is for profits that are reinvested). According to Law No. 13-01, for unconventional oil and gas, small deposits, and underexplored areas that have complex geology and/or that lack infrastructure, each company that is party to the agreement is subject to a reduced rate set at 19% (instead of the standard 30%) according to some specific conditions and depreciation rates.
Instead, the contracts signed under Law No. 86-14 have three different main taxes: the royalty tax, the income tax, and the above-mentioned windfall tax. With these contracts, royalty is due on the gross income, and it’s paid by Sonatrach at a rate of 20%. The royalty rate can be reduced to 16.25% for zone A and 12.5% for zone B. Moreover, The Ministry of Finance can reduce the royalty rate further to a limit of 10%. The income tax is fixed at the rate of 38%, it applies to the profit made by a foreign partner, and it is paid by Sonatrach on its behalf.
According to an analysis by Rystad Energy and the Boston Consulting Group, Algeria’s government take was 88% between 2009 and 2014. The government take may be defined as the government share of ‘gross revenues’ minus ‘costs.’ Indeed, this value is very high. It’s true that to analyze a petroleum contract, the government take parameter might not be a perfect indicator, but it’s also true that it may well serve as a useful initial reference point (Johnston 2003), and for this reason it’s used internationally as the measure for defining the competitiveness of a country’s petroleum fiscal system. The government take is even more important when oil prices decline and when the companies reduce their investments as well, because it’s exactly at that time that countries compete to attract the reduced number of possible investors.
Algeria is currently planning to amend its hydrocarbons law to attract investors because the last invitations to tender have resulted in negative outcomes. For example, in 2014, Algeria was capable of awarding only 4 blocks out 31 blocks on offer. All this said, it’s also true that the precarious security environment, especially in the areas far from the coastline, does not help to attract the I.O.C.s. An auction was planned for the second part of 2015, but it was canceled because of the negative results of the previous tenders. These negative results call for a more enticing regulatory framework (better tax provisions) capable of better balancing the interests of both Algeria, on the one side, and the I.O.C.s, on the other side.
Algeria needs both technical expertise and financial resources to explore those two-thirds of territory still today completely unexplored for oil and gas, and at the same time to start tapping its shale oil and shale gas resources. Maintaining Sonatrach’s 51% majority stake in all of Algeria’s hydrocarbons projects is probable is not tenable any longer; it’s time that the I.O.C.s have a larger role in the projects. Still today, Sonatrach owns about 80% of all oil and gas production. Similarly, the present tax law, which was drafted when oil prices were high, might be modified to better account for a different range of oil prices.
LIBYA’S PETROLEUM FISCAL FRAMEWORK
Libya’s petroleum development started in 1955 with the promulgation of Law. No. 25, a.k.a., the Petroleum Law. In the same year, Libya granted its first concessions—what was immediately interesting was that the concessions concerned small areas and that there were relinquishment obligations included. This law has been amended over the course of the following decades several times, and it’s still today the backbone of the country’s petroleum sector. Those first concessions gave the I.O.C.s the complete control over all the petroleum operations.
By the end of the 1960s and beginning of the 1970s, Libya started requesting tougher fiscal terms from the I.O.C.s. In specific, Libya wanted to have a larger share of the petroleum revenue, and, in 1970, it increased its royalties from the concession agreements with the I.O.C.s to a 55% share. Then, in 1972-1973, the concessions were transformed into participation agreements in which Libya’s National Oil Corporation (N.O.C., the petroleum state company) was entitled to a 51% stake. And, in 1973, a 51% stake in each of the concessions whose concessionaries had previously refused to transform their concessions into participation agreements was nationalized.
In 1974, Libya introduced its first exploration and production sharing contracts (E.P.S.A.s). In practice, the government decided to have a petroleum fiscal framework based on production sharing contracts (P.S.C.s). Until today, Libya has introduced four versions of the E.P.S.A.s. Today’s contract is the E.P.S.A. IV, which was used for the first time in January 2005 on the occasion of the first licensing round after the lift of the sanctions against Libya in 2004. The E.P.S.A. IV terms are quite tough, but this contract was quite successful in 2005 because at that time oil prices were rising, there were not many interesting acreages on offer across the globe, and Libya’s coastline is quite close to Europe, which has a large oil-importing market. In fact, the 2005 E.P.S.A. IV licensing round, which was a sealed-bid round, saw 15 blocks on offer and an average of 7 bids per block.
Since 2005, Libya has held four licensing rounds based on the E.P.S.A. IV. The first one in January 2005, the second one in October 2006, the third one in December 2006, and the last one in December 2007 (the latter exclusively for gas fields). In general terms, the first three rounds were quite successful (on average they had an 87% award rate), while the fourth one, the gas round, had only a 50% award rate. The reason for the disappointing result of the fourth round was that at least some of the I.O.C.s were quite unhappy with the strict terms and operating conditions. In fact, the winning I.O.C.s had all low production sharing percentages.
In any case, today if an I.O.C. wants to carry out petroleum operations in Libya, unless it takes over an existing interest, it must enter an E.P.S.A. IV with N.O.C. In general, if there is the need for I.O.C.s, the government organizes a bid round. I.O.C.s make their bids, and the winning company will open a branch office in Libya. The E.P.S.A. IV model provides for a contractual period of 30 years (5 years for the exploration and 25 years for the exploitation).
According to the E.P.S.A. IV, the I.O.C.s must bid the percentage of gross production directly reserved for the N.O.C.—later in the project, when the cumulative costs will be quite low, this share of gross production will appear more as a sort of regressive royalty. In case there is a tie on the gross-production percentage reserved for N.O.C., the signature bonus will be the tiebreaker. In 2005, the first time that Libya used the E.P.S.A. IV, the blocks on offer were quite large (on the order of more than 2 million acres each); large blocks may be a drag on the I.O.C.s because, in such a situation, companies might have important sunk costs before the discovery of a commercially..
ABSTRACT — Iraq’s fifth licensing round was related to the offering of 11 oil and gas blocks. In specific, 10 onshore blocks located along the Iraqi borders with Kuwait and Iran, and 1 offshore block in the Persian Gulf waters. In the end, six blocks were awarded, while five of the exploration blocks did not receive any bids. One initial explanation for the mixed result might be that the Iraqi government, for political reasons linked to the upcoming national elections, had previously changed the date of the auction. So, the international oil companies (I.O.C.s) did not have sufficient time to study the dossier relating to the 11 blocks on offer. With reference to the contracts, the Ministry of Oil has introduced some amendments that have changed the structure of Iraq’s service contracts. The amended contract is different in that it sets a link between oil prices and the remuneration given to the I.O.C.s. At the same time, it introduces a 25% royalty on gross production. Thanks to the new contractual structure, the government would like to force the contractors to act in a more efficient manner.
The analysis “Three Questions About Egypt’s Oil and Gas Sector,” has been published by the Oil and Gas Council, the leading network of energy executives in the world. This analysis is related to Africa Assembly 2018, which is the largest African O&G finance and investment event. The Oil and Gas Council will organize Africa Assembly 2018 on June 5-6 in Paris, France.
March 21, 2018
London, United Kingdom
1 — What is Egypt’s role in the O&G business on a global scale?
Egypt has been one of the first countries active in the petroleum extraction. In fact, the country has been producing crude oil for more than a century; Egypt’s first commercial crude oil production started in 1910 in the Sinai Peninsula. Today, according to BP Statistical Review of World Energy 2017, the country owns 3.5 billion barrels of proven oil reserves, which position Egypt as the 6th and 27th largest holder of proven oil reserves in Africa and in the world, respectively. Almost 50% of the oil production occurs in the Western Desert, while the remaining production is located in the Mediterranean Sea, the Nile Delta, the Gulf of Suez, and Upper Egypt (the latter is the southern part of the country).
Despite being a medium-sized oil producer with 691,000 b/d in 2016, Egypt’s oil consumption at 853,000 b/d is higher than its production (this is not surprising because Egypt has a population of 95.5 million), so Egypt has been recently obliged to import oil from other countries—mainly from Middle Eastern countries. Over the last forty years, oil’s share in total primary energy production has consistently been reduced (it was 95% in 1970 while it is today 44.6%)—of course, oil is the main fuel used for transportation.
However, the real added value in the O&G business for Egypt derives from the country’s natural gas reserves, which at 65.2 Tcf position Egypt as the 3rd and 16th largest holder of proven natural gas reserves in Africa and in the world, respectively. In 2016, Egypt was the third African natural gas producer with an overall annual production of 41.8 Bcm. Egypt’s natural gas sector started to expand at the end of the 1990s because of increased domestic demand and of the idea of exporting the excess natural gas as L.N.G. In 2009, Egypt’s natural gas production peaked at 62.7 Bcm, but, then, in 2010, production started to decline. The reason was that some of the offshore production areas in Mediterranean Sea had reached the maturity level while at the same investments were lacking because Egypt was slow in reimbursing the foreign contractors. On top of this, the oil price reduction in 2014 did not help attract foreign investments in the country.
The whole picture changed completely in 2015 when Italy’s E.N.I. announced the discovery of the Zohr field, a giant offshore gas field in the Mediterranean Sea at a depth of 1,450 meters with 30 Tcf of gas in place, of which 22 Tcf of recoverable reserves. In December 2017, E.N.I. started production at the Zohr field at the level of 350 MMcf/d. From this level, daily output is set to rise to about 1 Bcf/d in June 2018 and then 2.7 Bcf/d by the end of 2019. In addition to the Zohr field, other gas fields—West Nile Delta (recoverable reserves of 5 Tcf), Noroos (estimated reserves in place of 530 Bcf), and Atoll (recoverable reserves of 1.5 Tcf)—are increasing Egypt’s natural gas production. And the Egyptian Natural Gas Holding Company (EGAS) intends to launch soon a new licensing round centered on 9 blocks in mature areas in the eastern part of Egypt’s Mediterranean Sea. Later, this round will be followed by another round covering frontier areas in the western part of Egypt’s Mediterranean Sea. Summing up, there is a complete commitment toward discovering new gas reserves.
2 — In addition to O&G reserves, what is Egypt’s added value?
Geography and infrastructure. In fact, not only is Egypt gifted with O&G reserves, but also it is strategically located so that it is one of the world’s most important transit points for the physical trade of hydrocarbons. The Suez Canal is a transit waterway for oil and L.N.G. shipments, while the Sumed Pipeline (whose book capacity is set at 2.5 MMb/d) is the only alternative route in proximity of the Suez Canal to transport crude oil from the Red Sea to the Mediterranean Sea if tankers are not able to pass through the Suez Canal. If it were impossible to navigate through the Suez Canal or to use the Sumed Pipeline, tankers would be obliged to navigate around the Cape of Good Hope in South Africa. This would mean to increase both the costs and the shipping time. The Cape of Good Hope route would mean 15 more days of navigation to Europe and 8 days to 10 days more of navigation to the United States.
However, the recent natural gas discoveries throughout the eastern Mediterranean Sea in the offshore of Egypt, Cyprus (Aphrodite field, 4.5 Tcf; Calypso field, believed to hold 6 Tcf to 8 Tcf), and Israel (Tamar field, 10 Tcf; Leviathan field, 22 Tcf)—and with the future possibility of natural gas discoveries offshore Lebanon—for the time being, offshore Syria is completely out of the picture as a consequence of the civil war ravaging the country) has additionally increased the geographic importance of Egypt, which might become in the near future a regional energy hub with particular attention given to the trading and export of natural gas. The World Bank supports the development of Egypt’s role as an energy hub. It’s plausible that Egypt will be again a gas exporter in 2019. In any case, it is premature to know for how long Egypt will be a gas exporter—it depends on whether there will be new natural gas discoveries and on the country’s population growth. However, in addition to exporting its own gas, Egypt could export Cyprus’s and Israel’s gas. In fact, all the above-mentioned gas fields, the Zhor field included, are located very close to one another.
And, of all the mentioned countries, in addition to its advantageous geographical position, Egypt has already in place an export infrastructure. Egypt has two L.N.G terminals, one in Idku and one in Damietta. These terminals, which have a combined capacity of about 19 Bcm per year (Idku, 11.48 Bcm; Damietta, 7.56 Bcm) are currently not used. These terminals might well be used for exporting Cyprus’s and Israel’s gas. In addition, if Egypt were able to find a solution to its confrontation with Israel regarding Egypt’s shut off in 2012 of its gas exports to Israel via the El Arish-Ashkelon Pipeline, this pipeline (9 Bcm per year) would be again an important natural gas infrastructure in the region. Three arbitrators at the International Chamber of Commerce ruled that Egypt’s natural gas companies will have to pay Israeli Electric Corp. $1.76 billion for halting gas supplies. Instead, the future of the Arab Gas Pipeline, which connects Egypt to Syria and Lebanon, is difficult to understand considering the present conflict in Syria.
It’s necessary to underline that duplicating L.N.G. export infrastructure in all the involved countries would be economically illogical. At a time when it is quite important to limit both capital expenditure (capex) and operating expenditure (opex) per MMBtu of produced natural gas, building in Cyprus and/or in Israel export infrastructure already present in Egypt would eat away at the profitability of Cyprus’s and Israel’s gas exports. So, despite all the difficulties of the eastern Mediterranean geopolitics, collaboration among the involved actors—and, in specific, between Cyprus, Egypt, and Israel—would really go a long way in maintaining eastern Mediterranean natural gas prices competitive on the world markets.
3 — Is Egypt’s O&G fiscal framework attracting to international companies?
Egypt is one of the oldest oil producers in the world, which means that in the country there is a lot of experience in managing petroleum operations. Hydrocarbon production is by far the largest single industrial activity, representing approximately 16 percent of Egypt’s G.D.P. And the energy sector is the most important sector for foreign direct investment (F.D.I.) in the country.
Egypt’s petroleum fiscal framework has changed over the decades to reflect the evolution in the way of thinking how to structure a petroleum fiscal framework. Until 1962, Egypt based its framework on a royalty/tax system, then between 1963 and 1972 it moved to a participation system, and lastly, since 1973, it has been using a production sharing system.
The production sharing contracts that Egypt has signed over the years have had in general terms a positive result for both Egypt and the foreign companies—although it must be clear that unless a petroleum fiscal system has a lot of flexibility, which is always difficult to implement, it is improbable that it may always remain the same and give the same results over the years without any amendments.
One of the Egyptian P.S.C.s’ most attracting features to foreign companies is that in Egypt the P.S.C.s are enacted into law. In practice, this feature has always given foreign companies a lot of confidence that their investments are protected and upheld by national law. The downside is that, because of enacting contracts into law, it is then more complicated to renegotiate or amend the contracts—in fact, it’s required the approval of the Ministry of Petroleum and of Parliament. In addition, investments in Egypt are generally protected against expropriation, especially if there is a bilateral investment treaty between Egypt and the home country of the foreign investor.
When there is a commercial oil and/or gas discovery, a non-profit joint venture (J.V.) between the contractor company (50% stake) and Egypt’s competent company (50% stake)—the competent company may be the Egyptian General Petroleum Corporation (E.G.P.C.), the Egyptian Natural Gas Holding Company (EGAS), the Ganoub El Wadi Petroleum Holding Company (Ganope)—is established as a special joint stock company (the Operating Company). In all the contracts, the government is entitled to a 10% royalty calculated on the total quantity produced. However, Egypt’s competent company, and not the contractor company, pays the royalty. Similarly, the contractor company is subject to the Egyptian corporate income tax (C.I.T.), which for the O&G sector is set at the rate of 40.55%. However, who pays the contractor company’s C.I.T. is Egypt’s competent company, which pays the tax out of the competent company’s share of the petroleum produced and saved as defined in the P.S.C.
One of the challenges that continue to trouble the foreign companies investing in Egypt’s O&G sector is the issue of delayed payments. The Egyptian government is currently trying to pay out the remaining backlog of arrears to the I.O.C.s to encourage more foreign companies to invest in exploration and development activities, but this issue is still far from being fixed. The government had a peak of arrears at $6.3 billion in 2013, reduced to about $3.5 billion in March 2017.
In the past years, to increase hydrocarbons production, Egypt has offered more generous percentages for profit and cost recovery (expenditures with respect to exploration, development, and related operations). In specific, it raised cost recovery percentage from 35% to 40%. Still, along the same line, it was decided the abolition of the mandatory abandonment of part of the concession area every two years—the contractor can now present a new exploration plan for the concerned area and not abandon it.
This strategy has paid off because Egypt has signed several oil and gas exploration deals in the past years. With reference to natural gas, Egypt has signed natural gas deals according to which it pays foreign companies a higher price for the natural gas the companies produce—before the price was $2.65 per MMBtu, while the new prices range from $3.95 to $5.88 per MMBtu. In fact, before this contractual modification, some relevant gas discoveries remained undeveloped because foreign companies had not found any profitability in developing those discoveries at the previous prices.
The Ministry of Petroleum has established a joint committee to redraft the P.S.C.s and to introduce amendments that may incentivize foreign companies to enter Egypt’s O&G sector. According to the current timeframe, the committee should be able to present its result by the end of this year. One of the most important modifications should concern a reduced reimbursement period to stimulate foreign investment. The foreign companies already working in Egypt may forward suggestions to the committee. The basic idea is to provide the P.S.C.s with more flexibility, for instance, sharing production or surplus and, with natural gas, being able to modify over the course of the contract the price per MMBtu that Egypt pays to the foreign companies.
The analysis “Kuwait’s Petroleum Sector: What Is the Right Strategy?” has been written for the 5th Kuwait Oil and Gas Summit, which is organized by The C.W.C. Group, an energy and infrastructure conference, exhibition and training company. The 5th Kuwait Oil and Gas Summit will take place in Kuwait City, on April 16-17, 2018.
April 12, 2018
London, United Kingdom
With 101.5 billion barrels of oil (BP Statistical Review of World Energy 2017), Kuwait owns the world’s seventh largest proven oil reserves, or 5.9% of the world’s proven oil reserves. The country’s economy is dominated by the oil sector. In fact, more than 50% of the G.D.P, 92% of export revenues (from oil and oil products and fertilizers), and 90% of the government income come all from the oil sector (C.I.A. World Factbook, 2018). With reference to natural gas, Kuwait, with 1.8 trillion cubic meters (Tcm) of natural gas (BP Statistical Review of World Energy 2017), on par with Norway and Egypt, owns the world’s 16thlargest proven natural gas reserves, or 1.0% of the world’s proven natural gas reserves.
Kuwait has a production capacity of about 3.1 million barrels per day (MMb/d) and an effective production of about 2.7 MMb/d. Kuwait’s production of about 250,000 b/d at the Wafra (onshore) and Khafji (offshore) fields in the Partitioned Neutral Zone, which is the border region between Kuwait and Saudi Arabia, has been shut down since 2015. At the current rate of production, Kuwait’s oil should last for almost 88 years, while gas reserves for more than 100 years. Kuwait, as well as the other Persian Gulf producers, has a couple of important advantages: very low production costs and a geographic position at the crossroads of three continents (Europe, Africa, and Asia), which permits Kuwait to easily export oil and oil products to more than one market.
Kuwait has production costs among the lowest in the world. In fact, it has had until now production costs of about $8.50 per barrel on average (in specific, $3.70 for capital expenditures and $4.80 for operating expenditures). Probably, these production costs will relatively rise in the future because production will derive from more complex fields. However, because oil is a commodity (despite different A.P.I. degrees and sulfur content), low production costs are one of the most important commercial advantages for an oil producer.
At the same time, thanks to its geographic position, Kuwait may easily export its oil to the Asia-Pacific region, which receives about 80% of its oil exports (Kuwait’s overall exports are estimated at about 2.0 MMb/d). Crude oil is primarily sold on term contracts, and its crude oil exports have been until recently a single blend of all the Kuwaiti types of crudes, which is called ‘Kuwait.’ This blend has 30.5 A.P.I. degrees and 2.6% of sulfur content (it’s defined a sour crude). Presently, with the help of some Asian refiners, Kuwait is testing in Asia whether there might be some interest in a new Kuwaiti blend called ‘Super Light,’ which has an A.P.I. gravity of 48 degrees and 0.4% of sulfur content. In addition, in August 2018, Kuwait wants to launch the blend ‘Kuwait Heavy,’ which has an A.P.I. gravity of 16 degrees and 4.9% of sulfur content.
So, Kuwait represents a reliable and secure oil producer, which has been in the oil business since 1938 when oil was discovered four years after the signature of the concession in favor of a joint venture between Anglo-Persian Oil Company (today’s British Petroleum) and Gulf Oil (today part of the U.S. company Chevron). And, for all these decades, apart for a short hiatus linked to the invasion of Kuwait by Iraq’s army, Kuwait has been one of the world’s most important and reliable producers.
However, because of the evolving energy scenarios linked primarily to geopolitical considerations, disruptive technologies, and climate change goals, it has become more difficult for a petroleum-producing country to understand the future opportunities and challenges concerning the petroleum sector. In practice, the petroleum industry is in transformation, and all the petroleum-producing countries (but, it would be more correct to add all the petroleum-importing countries as well) must learn how to mitigate the present uncertainties. And, as a producer, Kuwait is not exempt from this difficult challenge.
In addition, these uncertainties regarding the development of the world’s petroleum industry are added in Kuwait to an economy that is completely dependent on the sales of oil and oil products. In fact, despite some attempts, Kuwait has not succeeded in diversifying its economy and in supporting the development of the private sector. The public sector employs about 74% of the citizens. Be it clear that these economic features are quite widespread among all the Persian Gulf producers (neighboring Iraq is experiencing the same economic problems in addition to high costs linked to the reconstruction after the ISIS insurgence).
The level of a country’s petroleum dependence can be measured according to several different methodologies. In any case, three good indicators may be: petroleum activities representing a sizable share of G.D.P., petroleum rents representing a sizable share of G.D.P., and petroleum exports representing a sizable share of the merchandising exports. In brief, Kuwait has high values in relation to all these three indicators.
What Did Kuwait Export in 2016? — Source: The Atlas of Complexity, Harvard University
The government had passed its first long-term economic development plan in 2010. The idea was to spend up $104 billion over just four years with the specific goal of diversifying the economy, bringing investments in Kuwait, and increasing the private-sector share of the economy. Many of these projects never materialized because of the uncertain political situation and the delays in awarding the contracts.
In Kuwait, diversification is not happening primarily for two reasons. First, because it’s never an easy task to diversify the economy of a commodity-producing country. And this is true no matter in what part of the world we are. Also, for a country like Norway, which is normally considered the model of a successful petroleum-producing country, diversifying the economy (although not completely) has not been an easy task, and several specific (of the Norwegian state) factors helped Norway reach this goal. In fact, for a commodity producer, there is always, behind the corner, the risk of facing two dangerous phenomena, i.e., the Resource Curse and the Dutch Disease.
Second, diversification is not happening in Kuwait because of the difficult relationships between the National Assembly, on the one side, and the executive branch, on the other side. Historically, in Kuwait, the relationships between these two institutional bodies have never been simple, and they have stymied many economic reforms proposed over the years. A strong confrontation between the National Assembly and government concerning the way to deal with the management of the natural resources according to the interpretation of the text of the Constitution had already materialized in the 1960s.
However, many petroleum-producing countries find themselves in dire financial straits after an oil’s price fall, as it occurred in 2014. So, if a country’s economy is based on just a single pillar, when this pillar is not any longer stable, there are bad economic consequences for the country. In practice, a single-pillar economy has lower resilience against shocks affecting its single pillar than the resilience of an economy based on several different pillars. And this is what exactly occurred to Kuwait. The adage ‘never put all the eggs in a single basket’ is true for private investors as it is for countries.
In fact, in 2015, for the first time in 15 years, Kuwait realized a budget deficit. The following year, the deficit increased to 16.5% of the G.D.P. Then, in 2017, the deficit decreased to 7.2%. At the same time, the government issued $8 billion’s worth of international bonds—there is a trend in this direction in the Gulf Cooperation Council (G.C.C.) region. Kuwait’s Fund for Future Generations, the sovereign wealth fund, in which each year Kuwait saves at least 10% of government revenues, helped cushion Kuwait against the impact of the reduction in the oil prices. Without capital expenditures and social allowances, the latter make up two thirds of the private sector salaries, the economy would have slowed more consistently.
Considering the above points, it appears clear that Kuwait’s overall economic development must pass through the diversification of the economy and a boost in private-sector hiring. However, as economic literature has well explained, this is easier said than done, especially in a country subject to harsh weather conditions as Kuwait is. Probably, the best route would be the development of industrial clusters linked to Kuwait’s characteristics and not a top-down industrial policy established by the government.
As the theory of cluster development explains, clusters pursue competitive advantage and specialization, and they do not attempt to replicate what is happening in other locations. With clusters,
[g]overnments – both national and local – have new roles to play. They must ensure the supply of high-quality inputs such as educated citizens and physical infrastructure. They must set the rules of competition – by protecting intellectual property and enforcing antitrust laws, for example – so that productivity and innovation will govern success in the economy. Finally, governments should promote cluster formation and upgrading and the buildup of public or quasi-public goods that have a significant impact on many linked businesses. This sort of role for government is a far cry from industrial policy. (Porter, 1998)
So, branching out to other industrial sectors according to a cluster logic may be the correct way. Kuwait might be the location for clusters related to technologies linked to living in hot environments. For instance, technologies linked to water desalinization, solar energy, and agriculture in arid lands.
Instead, with reference to the petroleum sector, the correct strategy, despite all the present uncertainties, must be continuity with the past. Here the logic must be to understand what Kuwait can and cannot do now and in the next years. In fact, notwithstanding all the ongoing discussions, it’s impossible for Kuwait not to rely on the revenues deriving from the sale of oil, which has been for the last decades and will continue to be, at least in the near future, the country’s most important asset. As of today, without oil revenues, numbers tell us that Kuwait’s economy would come to a grinding halt. Plus, it’s important to understand that diversifying the economy would take years before making a dent on the current structure of Kuwait’s economy, which is dependent on the export of oil and oil products.
In 1997, Kuwait formulated ‘Project Kuwait,’ at that time a $7 billion 25-year plan having the goal of increasing the country’s oil production capacity (and compensate for the decline at the supergiant Burgan field) with the help of international oil companies (I.O.C.s). In specific, Kuwait wanted to initially increase output at five northern oil fields—Abdali, Bahra, Ratqa, Raudhatain, and Sabriya—from a production rate of about 650,000 b/d to 900,000 b/d within the following three years. Then in mid-2000s, the basic idea of the project became to increase the country’s oil production capacity to 4.0 MMb/d by 2020.
This whole project has not materialized until now despite the authorities have always reaffirmed until recently that this is still an achievable target. The main reason for the delay is the political opposition to the I.O.C.s and to the contractual structure offered to them. Many of the new projects have faced relevant delays because of the National Assembly’s opposition to the envisaged new contractual structure. For more information about Kuwait’s petroleum contracts, please see: BACCI, A., Kuwait's Oil and Gas Contractual Framework and the Development of a Modern Natural Gas Industry (Dec. 2011).
In brief, in order to bring in Kuwait the I.O.C.s, at the end of the 2000s, Kuwait started to offer Enhanced Technical Service Agreements (E.T.S.A.s), which allow the foreign companies to provide technical expertise (needed especially for the more challenging fields) and management expertise for a fee. Kuwait’s politicians have always been quite skeptical about the transparency of the E.T.S.A.s and whether what Kuwait receives in exchange for these services is fair. In any case, in the past ten years, Kuwait has signed some E.T.S.A.s with Shell, BP, and Total, although the development of the contracts has been marred by several missed deadlines.
Kuwait won’t probably achieve the target of 4 MMb/d by 2020, but Kuwait Petroleum Corporation (K.P.C.) has recently affirmed that it intends to invest more than $500 billion to push its petroleum production to 4.75 MMb/d by 2040. Whether the 4.75 MMb/d target includes Kuwait's production from the neutral zone is not clear. In any case, this increase will derive mostly from northern Kuwait, which is currently producing 1 MMb/d. In specific, the company should spend $114 billion in capital expenditures over the next five years and additional $394 billion after the initial five years up to 2040.
In practice, although the petroleum market has changed consistently over the past 10 years, Kuwait proposes again an oil-production expansion plan. And, despite that Kuwait is subject to OPEC quotas and that OPEC and non-OPEC members are currently restraining their crude oil production to support oil prices, there is a logic behind this choice. And Kuwait is not the only country carrying out this type of plan. In fact, throughout the Persian Gulf oil-producing countries, there is a medium-term trend toward expanding crude oil production (see for instance the expansion plans relating to Iraq and Iran as well).
With reference to oil, all these countries share the same advantages that Kuwait has, i.e., low crude-oil production costs and an interesting geographic position capable of serving more than one market (the favored one is the Asian market now). And because oil is a commodity (let’s put aside the differences relating to A.P.I. degrees and sulfur content) and considering the two above-mentioned advantages, if oil markets were not affected by distortive political and economic barriers, it would be evident that the most obvious oil producers in the world should always be the Persian Gulf producers and Russia as well. Think of David Ricardo’s theory of comparative advantage. So, summing up, this medium-term trend tells us that these countries, including Kuwait, are betting on cashing in on these two mentioned advantages, if not today, on a medium-term horizon.
What Kuwait is slowly trying to achieve is probably the correct strategy under the present uncertain circumstances. In any case, selling oil and oil products will require a more detailed attention to the whole petroleum chain, from upstream to downstream. In fact, competition among producers is increasing both at the regional and at the international level with the specific goal of capturing opportunities in the market. For sure, Kuwait is well positioned to take advantage of the growing oil demand occurring in Asia, but this is true for all the other Persian Gulf producers as well, and it seems that in the future also oil producers from other geographic areas might try to sell oil in Asia. For Kuwait, enhancing customer relationships will be crucial to maintain prearranged fixed sales agreements, which guarantee a certain cash flow. Because oil is a commodity, differentiation strategies are not easy to implement. One route might be to have an enlarged role in relation to oil trading.
At the same time, Kuwait must necessarily continue to increase its production of non-associated natural gas; its associated natural gas production makes up 80% of the total natural gas production. According to BP Statistical Review of World Energy 2017, Kuwait in 2016 produced 17.1 billion cubic meters (Bcm) of natural gas, while it consumed 21.9 Bcm. The goal is to increase non-associated gas production to 2.5 billion cubic feet a day (Bcf/d) in 2040 from the level of 0.5 Bcf/d in mid-2018. Kuwait needs large supplies of natural gas to generate electricity and to carry out water desalination, petrochemical production, and enhanced oil recovery to boost oil production. In specific, the electricity sector often fails to generate enough electricity to meet peak demand.
Moreover, because Kuwait for a good share produces electricity by burning oil and other liquids, which in this way are not exported, Kuwait is currently losing revenues from the missed sales of this oil and other liquids. More domestic natural gas production from non-associated gas fields might free some quantities of oil for export with consequently the result of increasing the revenues for Kuwait. The need to increase natural gas availability is quite urgent because domestic energy demand is going to double between 2017 and 2030.
Kuwait has been relying on L.N.G. imports since 2009 when natural gas consumption overpassed domestic production, and this trend seems not to abase. In December 2017, K.P.C. signed a 15-year L.N.G. gas import deal with Shell (the deal will start in 2020) to help Kuwait to continue to close the gap between its gas demand and its gas production. At the end of the 2000s, the country started to develop, although slowly, its non-associated gas reserves, primarily from the Jurassic non-associated gas field (technically quite challenging) in norther Kuwait. This field was discovered in 2006 and has 35 Tcf of estimated reserves. In 2017, the government approved the second phase of the North Kuwait Jurassic Gas project, and, finally, this year three early production facilities, Sabriya and Umm Niqa fields, East Raudhatain field, and West Raudhatain field are coming online. Together, these facilities will produce 200,000 b/d of light crude and 500 MMcf/d of natural gas.
I would like to share with you the analysis “Lebanon’s Petroleum Sector: The Correct Expectations,” which I have recently written on the occasion of Lebanon International Investment Forum, a two-day investment forum organized in Beirut, Lebanon by the C.W.C. Group on April 10-11, 2018.
I would like to share with you the document that I prepared for my speech at the welcome coffee and breakfast briefing “Enhancing International Investment in Iraq’s Energy Sector” on the morning of February 28, at Iraq Petroleum 2018.
Iraq Petroleum 2018, as usual organized by the C.W.C. Group, was held this year in Berlin, Germany, on February 27-28.
This analysis has been written for Iraq Petroleum 2018, which is organized by The C.W.C. Group, an energy and infrastructure conference, exhibition and training company. This year, the conference will take place in Berlin, Germany, on February 27-28, 2018.
February 7, 2018
LONDON — After the important military victories obtained in the past months against the Islamic State, 2018 must be for Iraq the year of the country’s political and economic consolidation. In May 2018, there will be the parliamentary elections of the Council of Representatives, which will in turn elect the Iraqi president and prime minister. At the same time, it is quite evident that political stability is deeply intertwined with the development of Iraq’s economy. And, if on the one hand, without strong and unified political institutions, there won’t be credible economic development, on the other hand, without a strong economic sector, there won’t be firm and lasting political institutions.
Relaunching and improving Iraq’s economy cannot be separated from supporting and expanding the development of the petroleum (oil and gas) industry in the country. Today, Iraq’s economy is the world’s most dependent on oil. Approximately 58% of the country’s G.D.P. and almost 94% of its exports are petroleum oils; oil provides more than 90% of government revenues and 80% of foreign exchange earnings. These numbers tell that thinking of alternative economic routes—other than the hydrocarbons route—to provide the Iraqi government with the economic resources necessary to manage the country is premature. Oil is Iraq’s national treasure. In January 2018, Iraq produced 4.36 million barrels of crude oil per day and exported from its southern ports 3.53 million barrels per day—Iraq’s total exports should be higher if we add 200,000 barrels per day exported by the Kurdistan Regional Government (K.R.G.) to Ceyhan, Turkey.
What Did Iraq Export in 2016? — Source: The Atlas of Complexity, Harvard University
Absolutely, this does not mean to rule out the development of other economic sectors apart from the petroleum sector, but it’s an honest assessment of what can be done and what cannot be done at this point in time. The draft federal budget law of Iraq for 2018 confirms this point (data of November 2017). In fact, the draft law reveals estimated revenues of more than 85.331 trillion dinars, of which about 72 trillion dinars comes from the oil sector. The oil revenue was calculated on the basis of $43.4 per barrel of oil, but of course, higher oil prices mean a higher oil-sector revenue. Presently, Iraq’s overall development must pass through the production of oil and gas.
Prime Minister Haider al-Abadi has recently stated at the World Economic Forum, in Davos, Switzerland, that his country might need up to $100 billion to fix its crumbling infrastructure and severely damaged cities. The prime minister made very clear that Iraq cannot provide this amount through its own budget, nor will donations provide it. These economic resources must arrive in Iraq in the shape of foreign direct investment (F.D.I.).
THE I.O.C.s’ APPROACH AS FOR INVESTING IN IRAQ
With reference to the oil and gas sector, the international oil companies (I.O.C.s) are carrying out more than one approach concerning whether to invest in Iraq. In general, the I.O.C.s do not share the same vision regarding their investment presence throughout the world. Minister of Oil Jabbar Al-Lueibi has recently called on the I.O.C.s to participate in tenders organized by the Ministry of Oil and affirmed that Iraq is improving the work conditions for foreign firms that want to do business in the country.
In Iraq, Anglo-Dutch Shell wants to exit its oil investments, while U.S. Chevron wants to continue investing in the country with the idea of possibly expanding its portfolio. In specific, Shell, with the approval of the federal government, has very recently sold its 20% stake in the giant oil field West Qurna 1 to Japan’s Itoche Corporation. In West Qurna 1, the other members of the operating consortium are U.S. ExxonMobil (the operator, 33% stake), PetroChina (25%), Iraq's state-run Oil Exploration Company (12%) and Indonesia’s Pertamina (10%). Moreover, Shell wants to divest of its stake in the giant oil field Majnoon as well; it’s currently planning to hand over its stake to Basra Oil Company (B.O.C.) by the end of June 2018—the Iraqi government is forming an executive committee to operate the field after the withdrawal of Shell. Presently, at the Majnoon field, Shell is the operator (45% stake), while the other members of the consortium are Malaysia’s Petronas (30%), and Iraq's state-run Missan Oil Company (25%). In addition to Shell, also Petronas wants to exit this investment.
Conversely, Chevron affirmed in mid-January 2018 that it intended to return to its investments in the K.R.G. with the goal of restarting there its drilling operations, which it had stopped last fall when the tension between the K.R.G. and Iraq proper had mounted up. At the same time, Chevron might form a consortium with Total and PetroChina to develop the Majnoon oilfield. Moreover, the Iraqi authorities declared last fall that China National Petroleum Corporation (C.N.P.C.), British Petroleum, and Italy’s E.N.I. were all possibly interested in taking over a stake in the Majnoon oil field.
After the events of last October between the K.R.G. and Iraq proper, the presence of an additional oil major, Chevron, in both the K.R.G. and in Iraq proper might really be a diplomatic tool capable of helping appease the tense relationships between Erbil and Baghdad. In this regard, four months after the reoccupation by the federal troops of the oil fields around Kirkuk, it’s still unclear how the K.R.G. and Iraq proper will solve their quarrel—a point of convergence between the two parties might be found on the basis that the K.R.G. needs cash while Iraq proper wants to continue exporting crude oil via the Kurdish pipeline.
In specific, it will be interesting to understand whether in the whole Iraq (Iraq proper and the K.R.G.), after the political developments of the past four months, it will be prolonged the coexistence of two types of petroleum contracts, i.e., technical service contracts (T.S.C.s) in Iraq proper and production sharing contracts (P.S.C.s) in the K.R.G. In fact, since the signature of the first P.S.C. by U.K.-Turkish Genel Energy and the K.R.G. for the Taq Taq field in July 2002 (before the fall of Saddam Hussein, although the contract was then amended in January 2004) the federal government has been declaring the K.R.G. P.S.C.s illegal because according to the federal government the only authority wielding the power to sign off on petroleum contracts for the whole Iraq is the federal government. It’s in the last ten years that the K.R.G. has signed most of its P.S.C.s.
IRAQ AND THE I.O.C.s WANT TO CHANGE THE PRESENT T.S.C.s
When Iraq reopened its petroleum sector to the I.O.C.s, it chose to use T.S.C.s because they permitted Iraq to retain more control over the reserves and produced oil and gas while maintaining full control over the production rate and operation progress. Despite the reasons behind this choice, it’s a matter of fact that presently neither the government nor the I.O.C.s are happy with the T.S.C.s. So, if Iraq wants to improve the attractiveness of its upstream petroleum sector, it has to revise the terms of the T.S.C.s. In fact, if on the one hand, the Iraqi petroleum model contract gives satisfactory results to the Iraqi government when oil prices are high, on the other hand, it has a disastrous impact on the Iraqi coffers when oil prices are low. The reason is that, despite low oil prices, the federal government must always pay the same fees to the I.O.C.s.
Below are the key features of Iraq’s T.S.C.s (the following information comes from the Rumaila T.S.C.—Rumaila was an already producing field when the federal government auctioned it off in 2009):
Duration —The duration of T.S.C.s in Iraq is 20 years extendable to 25 years.
License —The license is held by one of Iraq’s national oil companies (N.O.C.s). In the original T.S.C., the N.O.C.s had a 25% stake in the winning consortium, but over the years this stake in some of the T.S.C.s has been reduced.
Signature Bonus — The I.O.C.s pay a signature bonus in cash upon the signature of a T.S.C. The initial T.S.C.s envisaged the signature bonus as recoverable, in practice, it was a soft loan that the I.O.C.s made to the government. It seems that the government of Iraq has now slashed some signature bonuses and transformed them into lower unrecoverable payments.
Remuneration Fee — (1st bid term in the bid round) The I.O.C.s receive a fixed remuneration fee per barrel of crude oil applicable for all calendar quarters during any given calendar year. This fee is determined on the basis of an R-factor calculated at the end of the preceding calendar year for the field. The remuneration fee starts at the level that was the bid by the I.O.C.s. However, as the profitability of the operations goes up, the fees go down on the basis of a percentage scale in the contract.
Baseline Production Rate — This is the field’s production rate before any development. The contracts assume that this baseline production rate declines at the compounded annual rate of 5%.
Incremental Production During a Period of Time — This is the incremental volume of net production from the field during the said period that is realized in excess of the deemed net production volume at the baseline production rate.
Petroleum Costs Recovery — The I.O.C.s receive reimbursement through service fees relating to the costs and expenditures incurred and/or the payments made by the I.O.C.s in connection with or in relation to the conduct of petroleum operations (capex and opex are included, but the corporate income taxes paid in Iraq are not included) determined in accordance with the provisions of the T.S.C.s.
Petroleum Operations — Petroleum operations encompass all appraisal, development, redevelopment, production operations, and any other related activities.
Supplementary Costs Recovery — Supplementary costs are non-petroleum costs, which primarily include the signature bonus (now it would probably more correct to say “included”) and de-mining costs. Service fees payments cannot exceed 50% of the deemed revenue of the incremental production.
Plateau Production Target — (2nd bid term in the bid round) All the contracts have a set production plateau to achieve in a specific time frame.
Corporate Income Tax (C.I.T.) — It’s set at 35%. The government deducts the 35% C.I.T. from the remuneration fees to the I.O.C.s. The income tax is received as crude oil.
Payments to Contractors — The I.O.C.s are required to withhold 7% of all the payments to subcontractors and to remit these deductions in cash to Iraq’s General Commission on Taxes.
Force Majeure — The non-performance or delay in performance by either party of its obligations or duties under this contract shall be excused if and to the extent that such non-performance or delay is caused by force majeure.
According to the T.S.C.s, the payments from the federal government to the I.O.C.s are based on production levels and not on the specific project revenue—it’s always a fixed amount for every barrel of crude oil produced. So, with low oil prices, the government earns necessarily less. In September 2016, Platts, one source of benchmark price assessment in the physical energy market, estimated that the proportion of oil revenues paid in cost recovery and remuneration fees was around 16% when oil prices were above $100 per barrel, but that it rose to as high as 48% with significantly lower crude oil prices.
And, to add insult to injury, as per their contract, until they reach the established production plateau, the I.O.C.s must increase their crude oil production. And the more barrels are produced, the more fees the federal government must pay to the I.O.C.s despite low oil prices. In general, this payment is done in kind, which means that, with low oil prices, the federal government needs a greater volume of crude oil to pay the I.O.C.s.
At the same time, the I.O.C.s have never been particularly fond of the T.S.C.s because the reimbursement fee was quite low for production after a certain threshold and because there were important upfront costs they had to sustain. In any case, at the time of their signature, the I.O.C.s decided to invest in Iraq because
it was important to re-enter Iraq after the nationalization of the 1970s
the first two rounds concerned already-discovered large fields (no exploratory risk)
the cost recovery was quite rapid so that project financing costs were reduced
However, also for the I.O.C.s. there is something more. With low oil prices, the T.S.C.s prescribe that the I.O.C.s’ remuneration should remain the same, but if the federal government is not able to pay, it will postpone its payments, i.e., the I.O.C.s will have increased financing costs. In addition, cost recovery is capped to a percentage of “deemed value,” which is “net production” in a quarter multiplied by the “provisional export oil price” for that quarter. This means that with low oil prices, there could be a decrease in the amount received by the I.O.C.s. as well.
Additionally, on the one hand, the I.O.C.s complain consistently about procurement procedures in Iraq. In fact, the applied lowest price principle initially reduces the costs, but later it increases them because the subcontractors to obtain their contracts propose low bids, which are impossible to carry out in the future if not with additional expenditures. However, on the other hand, because Iraq obtains 100% of the revenue after cost recovery and remuneration fee, the I.O.C.s get more profit if the costs are higher. In the end, there is no real incentive for the I.O.C.s to be cost efficient; what is missing is a way for the I.O.C.s to work in a more efficient and cost-effective manner.
Summing up, independently of what investment strategy the I.O.C.s want to carry out in Iraq, the sure recipe for the Iraqi government to getting a better profitability for itself from the country’s petroleum sector is to improve the terms of its T.S.C.s. At the same time, with the present oil prices, improved fiscal terms are of paramount importance also to attract the I.O.C.s. This logic holds true for both oil and gas fields on offer through licensing rounds and for oil and gas fields on offer through direct negotiations.
THE PAST FOUR BID ROUNDS AND THE “PROJECT”
Until now, Iraq has organized four bid rounds since 2009:
First Round (June 2009) — This round included the supergiant oil fields Rumaila, Zubair, and West Qurna 1, which had been until then under the operatorship of Iraq’s South Oil Company (S.O.C., today known as Basra Oil Company, B.O.C.). In total, eight fields were on offer. Companies were bidding on two parameters: remuneration fee and plateau production target. Initially, this bid round auctioned off successfully only the Rumaila oil field to BP for a remuneration fee of $2, but, on the bidding day, BP did not sign any contract and all the other seven auctioned fields were not assigned. Only after some months, did BP sign its contract for Rumaila. However, it was a modified version of the contract because, while the remuneration fee stayed the same, the cost recovery was quicker so that project financing costs were reduced giving the company an improved net present value (N.P.V.)—according to BP, after the amendments, the return on the investment was about 20%. Thanks to the improved terms, after the Rumaila signature, Iraq signed contracts also for Zubair, West Qurna 1, and Maysan (oil).
Second Round (December 2009) — In this second bid round, Iraq awarded seven oil fields: Majnoon, West Qurna 2, Halfaya, Garraf, Badra, Qaiyarah, and Najmeh. The three other fields on offer did not receive any bids; companies were probably worried by the security conditions on the fields or they could not see an interesting profitability in signing T.S.C.s for those fields.
Third Round (October 2010) — Iraq had not been able to sign off on a single gas contract with its first two bid rounds, so the country organized a round where there were on offer only three gas fields: Akkas, Siba, and Mansuriya. In fact, developing dedicated gas production for supplying domestic power plants and the petrochemical industry was preferred to using associated gas obtained from the oil fields. Few small companies showed up the day of the bid round, but all the three gas fields were awarded.
Fourth Round (May 2012) — The fourth round pertained to auctioning 12 blocks (called block 1, 2, 3, and so on) scattered throughout the country with the goal of exploring for oil. In other words, we are not talking of rehabilitating or increasing the production of already producing fields but of exploring for oil. This bid was unsuccessful for Iraq because only three blocks (blocks 8,9, and 10) were awarded. The reason for the failure was that the terms were not guaranteeing the oil companies sufficient profits.
FLORENCE, Italy — One aspect of corporate foreign policy that is not any longer so basic a tenet as it was during the latter part of the 20th century is the necessity of being or at least appearing neutral. Neutrality may be defined as the state of not supporting or helping (physically and ideologically) either side in a conflict or disagreement. Exactly because for a multinational company, corporate foreign policy, which subsumes in its definition corporate diplomacy and geopolitical due diligence, is becoming central to winning internationally, a basic neutral approach is too limited to guarantee in every instance positive results.
Starting in the mid-1980s, international companies have presented themselves as a sort of apolitical players, which, among their core goals, have an interest in the advancement of the societal environment of the countries where they invest. Indeed, this attitude is a complete sea change from the corporate foreign policy of the 1950s and 1960s when companies often carried out a neocolonialist strategy, which strongly influenced the internal politics of many weak states.
A good example of the neocolonialist behavior was the complicity of United Fruit Company, an American corporation that traded in tropical fruit, with the U.S. government in the 1954 coup in Guatemala. A coup that ousted the democratically elected leader of Guatemala, President Jacobo Arbenz, and resulted in more than three decades of military strongmen at the helm of the country.
Since the mid-1980s international companies have shunned any political involvement, while at the same time they have tried to implement a good corporate social responsibility (C.S.R.), to protect and improve their brand perception and reputational risk management, to cultivate stakeholder management, and to adopt better public relations with N.G.O.s.
With hindsight, these promotional tools have never given the international companies a real edge with reference to high-impact geopolitical events such as coups, regional and civil wars, internal power struggles, changes in the political status of key local partners, and changes in the public sentiment toward the company. In other words, only through their neutral approach and the tools developed after the mid-1980s, the international companies cannot really protect themselves and thrive in the much more unstable world that emerged at the end of the Cold War.
A clear illustration of the problems deriving from maintaining a neutral approach concerns the energy investments in Iraq proper and Iraqi Kurdistan. The latter is also known as the Kurdistan Regional Government (the K.R.G.) and is a semi-autonomous region within Iraq. Without entering into too much detail, it’s important to understand that after World War I, for all the 20th century, the relations between the Kurdish population based in what is today’s K.R.G. and those who exerted their rule over that area had been very tense and experienced several episodes of violent conflicts.
The relations between Erbil and Baghdad worsened again at the end of 2007 when the K.R.G. started signing production sharing contracts (P.S.C.) with small- and medium-sized companies without prior authorization from the federal government — in addition, the latter has never signed P.S.C.s but only technical service contracts (T.S.C.s). Baghdad has always said that it alone has the right to negotiate and sign energy deals for the whole Iraqi territory, the K.R.G. included. Instead, Erbil insists that Iraq's Constitutionallows it to agree to contracts, and as a result to ship oil independently of the central government.
In October 2011, tensions rose to a higher level when the U.S. supermajor Exxon Mobil, a company that was already the operator of West Qurna 1, a giant oilfield in southern Iraq, signed an oil deal related to the development of six exploration blocks in the K.R.G. — in December 2016 Exxon Mobil pulled out of three of these six blocks, but this move was not due to Baghdad’s pressure.
Exxon Mobil was the first supermajor to sign oil deals with Iraqi Kurdistan, and the federal government was literally scared that Exxon Mobil could act as a sort of trailblazer opening Iraqi Kurdistan to Big Oil investments. In fact, for Baghdad, one thing was to confront a K.R.G. receiving its economic legitimacy from small- and medium-size oil companies, one completely different thing was to confront a K.R.G. receiving its economic legitimacy from the supermajors.
The federal government wanted to appear resolute against Exxon Mobil — as it had done until then with the small- and medium-sized companies that had invested in the K.R.G until then. So, Baghdad immediately menaced to push Exxon Mobil out of Iraq proper stripping the company of its West Qurna 1 contract — the U.S. company had a 60 percent share in that oil field — if it hadn’t relinquished its Kurdish investments. Today, after almost 6 years, Exxon Mobil is still an investor in both the K.R.G. (with three blocks) and in Iraq proper (in West Qurna 1, where it’s still the operator, although with a 25 percent share).
In Iraq (Iraq proper and the K.R.G.), there is a sort of dichotomy regarding the energy investment strategies on the part of the international oil companies (I.O.C.s). In practice, some companies have decided to invest only in the K.R.G. (among them, U.S. Chevron, Korea National Oil Company, China’s Addax Petroleum/Sinopec, and Norway’s D.N.O. ), while others have decided to invest only in Iraq proper (among them, British Petroleum, Anglo-Dutch Shell, Japan Petroleum Exploration Company, Russia’s Lukoil and Rosneft, and China’s Cnooc and C.N.P.C). The only energy companies that escape this dichotomy and consequently have investments in both Iraq proper and the K.R.G. are Exxon Mobil, Russia’s Gazprom, and France’s Total.
A neutral approach may be useful when in a country there are completely unstable political conditions (for instance, military clashes/open war), and when it seems probable that in the short term there could be a clear and definitive political solution. But, when the quarrelling parties are not physically fighting between themselves, and when it appears highly improbable that there will be a final arrangement any time soon, a neutral approach may represent for a company only a lost economic opportunity. In the case of the K.R.G. and Iraq proper, neutrality is probably not useful.
Both the K.R.G. and Iraq proper have oil and gas reserves located in areas that can be easily protected from the Islamic State — Kirkuk oil fields may be more exposed, but let’s focus our attention only on the fields within the K.R.G. and on those in southern Iraq. Moreover, it seems evident that the tensions between Erbil and Baghdad won’t be gone soon — these tensions date back several decades. In fact, if the emergence of the Islamic State and its destruction of the Iraqi side of the Kirkuk-Ceyhan pipeline has forced the K.R.G. to build its system of export pipelines, which could be seen as a first step toward a K.R.G. economic independence, it also true that low oil prices, a complicated geopolitical environment, and oil reserves not as large as initially thought — a better assessment is needed — could induce the K.R.G. to continue with its tense cohabitation with Iraq proper.
In the end, can international companies wait for a real improvement in the relations between the K.R.G. and Iraq proper before doing business in the area? In other words, can they wait for a political improvement that might occur one year, three years, five years, or ten years from now? The answer is no, because as usual uncertainty is business’s worst enemy. In Iraq, neutrality is a way to lose economic opportunities. Instead, if companies want to succeed, they have to decide where they want to invest and then they have to act consequently.
India’s Reliance Industries sold its two blocks in the K.R.G. to Chevron because it wanted to pursue other economic ventures in Iraq proper from which it could have been barred if it had continued with its K.R.G. investments. Exxon Mobil, Total, and Gazprom had a different leverage over the federal government when they invested in the K.R.G — respectively in October 2011, July 2012, and August 2012. In fact, at that time, they had already signed service contracts related to the development of three of Iraq’s largest fields
ExxonMobil for West Qurna 1 (Iraq's first licensing round in 2009)
Total for Halfaya (Iraq's second licensing round in 2009)
Gazprom for Badra (Iraq's second licensing round in 2009)
In other words, for Baghdad it was very difficult, because economically unappealing, to strip these three companies of the contracts signed in the previous two or three years — contracts of paramount importance for relaunching and expanding the Iraqi oil sector.
But, it’s Shell’s approach that confirms how a corporate foreign policy based on a neutral approach could have been a very risky option in Iraq. In fact, if, on the one side, Shell was part to the initial negotiations that Exxon Mobil developed with the K.R.G. in 2011, on the other side, it was already deeply involved in Iraq proper with relevant investments.
In fact, Shell was Exxon Mobil’s junior partner (15 percent share) in the West Qurna 1 field (8.7 billion of recoverable barrels of oil) and the operator (45 percent share) in the Majnoon field in southern Iraq (13 billion of recoverable barrels of oil). But, at that time, Shell was also in the final stages of the talks that would end in November 2011 with the signature of a $17.2 billion’s worth deal with the federal government for collecting and processing all the natural gas from three of Iraq's giant southern oilfields, i.e., Rumaila, West Qurna 1, and Zubair.
In the end, Shell’s real interest in Iraq weights the balance in favor of investing in Iraq proper only. If Shell had signed a deal with the K.R.G., the federal government might have scuttled the gas deal, which was the weak link for Shell — for the same reasons explained above in relation to Exxon Mobil and its investment in West Qurna 1, it would have been quite difficult to strip Shell of the Majnoon contract. Moreover, what is sure is that for Shell a neutral approach would have meant not investing in Iraq proper nor in the K.R.G. with all the economic lost opportunities that this action would have encompassed.