Friday, June 1, 2018

A Snapshot of South Sudan’s Oil Sector

BACCI-A-Snapshot-of-South-Sudans-Oil-Sector-June-2018-Cover



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

INTRODUCTION

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 War from 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) 1 affirms 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.



Wednesday, May 16, 2018

Algeria’s and Libya’s Petroleum Fiscal Frameworks

BACCI-Algerias-and-Libyas-Petroleum-Fiscal-Frameworks-May-2018-Cover



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

INTRODUCTION

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, 11th position 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 exploitable quantity of hydrocarbons.       

In addition to the signature bonus, each block on offer has several production bonuses linked to the cumulative production coming out of the block. The E.P.S.A. IV requires N.O.C to pay 50% of capital expenditures (capex) and its share (percentage) of operating expenditures (opex, this share corresponds to the gross-production percentage reserved for N.O.C., i.e., the first (and fundamental) bid parameter. N.O.C. does not directly cover the exploration costs. These costs are directly expensed by the I.O.C.s, which could recover them as cost oil.

The I.O.C.s’ cost oil comprises three elements:

1 — 100% of exploration costs

2 — 50% of capex

3 — the ‘%’ of opex corresponding to the ‘%’ of the I.O.C.s’ gross production

In any calendar year, a specific percentage of production must be allocated to the I.O.C.s for cost recovery until the cumulative value of such allocation equals the cumulative petroleum operations expenditures incurred by the I.O.C.s. Thereafter, any excess of such allocation to the I.O.C.s (Excess Petroleum) shall be allocated to the I.O.C.s according to the formula: ‘Base Factor’ multiplied by ‘A Factor’ multiplied by ‘Excess Petroleum.’

The base factor at the indicated levels of the average total daily production in barrels of crude oil and liquid hydrocarbon by-product, is defined by a specific table according to which the various levels of production have a different base factor. In practice, if, for example, excess oil is 50,000 b/d, the base factor will be for the first 20,000 barrels 0.95, for the second 10,000 barrels 0.80, and for the remaining 20,000 barrels 0.60. If we multiply each tranche of barrels by its corresponding base factor, sum the results, and then divide the result of the sum by the overall excess oil, we will get the final base factor. Instead, the A factor is the result of dividing the I.O.C.s’ cumulative revenues by the relating expenditures (the sum of both capex and opex). According to the obtained ratio, the I.O.C.s will use a different A factor as expressed in a specific table. N.O.C. pays the taxes on behalf of the I.O.C.s.

The overall result of the 2005 E.P.S.A.s was that the government had a government take on the order of about 88% across all the blocks. This percentage was very high despite the government participated in 50% of capex and in a percentage of opex corresponding to the percentage value of its reserved gross production. And, according to an analysis by Rystad Energy and the Boston Consulting Group, Libya’s government take was 76% between 2009 and 2014. The basic idea is that the contractual terms of the E.P.S.A. IV are quite harsh. According to these terms, some discoveries, despite being quite large, may sometimes not be sufficiently large to declare them commercially viable.      

Already before the commencement of the hostilities against Colonel Gaddafi, in Libya there was the idea of passing a new and more encompassing hydrocarbon law with specific chapters covering natural gas and enhanced oil recovery (E.O.R.) projects. Moreover, immediately after the demise of Colonel Gaddafi’s regime, some of the discussions focused on the structure and the management of the hydrocarbons industry with specific attention given to expanding the downstream sector, reforming the subsidies, restructuring N.O.C., and amending the upstream contracts.  N.O.C. was thinking of having another bid round as well. However, because of the ongoing civil war, all this program has been put on the backburner.   

The I.O.C.s would like Libya to present an updated version of the E.P.S.A. with more attractive terms with reference to the companies’ profitability. At the same time, the companies would like to have some reforms concerning the way the management committee works, the application of force majeure, and the training and employment of Libyan nationals. In specific, the problem with the management committee is that sometimes this body is incapable of taking decisions because there is no unanimous decision, which is instead mandatorily requested. If there is this deadlock, the matter at hand is then passed to the senior management. However, it’s not guaranteed that a solution will be found also at this level. So, delays may be a regular occurrence, which has a negative impact on the contractual obligations.



Monday, May 7, 2018

Iraq’s Fifth Licensing Round: Some Preliminary Considerations After the Auction

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May 7, 2018
London, United Kingdom

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.





Thursday, April 26, 2018

Current Trends Concerning Petroleum Service Contracts in the Middle East

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April 26, 2018

London, United Kingdom

Dear friends,

I would like to share with you the presentation that I gave at the European Chapter Event International — Petroleum Scholar Workshop, which was organized in London, United Kingdom, by the Association of International Petroleum Negotiators (A.I.P.N.) on April 26, 2018.  

Thank you.

Best regards,

Alessandro

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Thursday, April 12, 2018

Kuwait’s Petroleum Sector: What Is the Right Strategy?

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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 16th largest 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.

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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.

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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.

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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.

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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.