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.



Tuesday, April 3, 2018

Lebanon’s Petroleum Sector: The Correct Expectations

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April 3, 2018

London, United Kingdom

Dear friends,

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.   

Thank you.

Kind regards,

Alessandro

Wednesday, March 21, 2018

Three Questions About Egypt’s Oil and Gas Sector

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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.   

Wednesday, February 28, 2018

Iraq Petroleum 2018 — Enhancing International Investment in Iraq's Energy Sector

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February 28, 2018

Berlin, Germany

Dear friends,

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.    

Thank you.

Best regards,

Alessandro



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Tuesday, February 20, 2018

Iraq Petroleum 2018 — Natural Gas Must Be an Asset for Iraq

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My report “Iraq Petroleum2018 — Natural Gas Must Be an Asset for Iraq” has been published on February 20, 2017, by Iraq Business News

February 20,

LONDON, United Kingdom

ABSTRACT — On February 27-28, 2018, the C.W.C. Group, an energy and infrastructure conference, exhibition and training company, will organize in Berlin, Germany, the twelfth edition of Iraq Petroleum, which is one of the major events concerning Iraq’s oil and gas sector. One of the main topics of Iraq Petroleum 2018 will be the development of Iraq’s natural gas reserves with the specific goal of strengthening energy-intensive industries to diversify the Iraqi economy. In Iraq, natural gas might really be the key driver to develop additional industrial sectors. In fact, natural gas may be used for power generation (electricity), petrochemicals, fertilizers, and other heavy industries in which gas is the primary feedstock. In this regard, some analysts might object that the development of these new industrial sectors would not really change the picture for Iraq because its economic development would still be too linked to the oil and gas sector—in practice Iraq’s economy would continue to be overaffected by the price of oil and gas. This observation is by no means wrong, but it’s also true that, apart from increasing oil exports (and in this regard, it will be important to see how Iraq will deal in the future with OPEC’s quota restrictions) to improve its economic standing Iraq does not have many alternatives to developing its natural gas resources and then using them to add other industrial sectors to the economy.


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What Did Iraq Export in 2016? — Source: The Atlas of Complexity, Harvard University




Wednesday, February 7, 2018

Iraq Petroleum 2018 — The Importance of Improved Fiscal Terms

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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. 

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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.


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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

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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.   

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So, in the end, despite some difficulties, especially for the first bid round, the first three bid rounds have been successful for Iraq. Instead, the fourth one has not provided Iraq with a positive outcome. In any case, it was with the three first rounds that Iraq literally opened its oil and gas sector to the I.O.C.s. It’s important to underline that, if the companies had been able to meet their contract targets, the eleven oil contracts signed with the first two bid rounds would have increased the country’s oil production by about 11.7 million barrels by 2018.    

The four bid rounds show the importance of finding a balance between the government’s interests and the companies’ interests. However, at the same time, licensing rounds are a very good tool for finding out how a government and the interested companies view the assets on offer. Many a time, value evaluation of the assets may be completely different. For example, in Iraq, in the first licensing round, with reference to the Bai Hassan field, there was a significant difference between the remuneration fee offered by a consortium formed by U.S. ConocoPhillips, and two Chinese companies, China National Offshore Oil Corporation (Cnooc) and Sinopec. The companies requested a remuneration fee of $26.70, but the maximum remuneration fee that Iraq was available to pay was $4.00. As a result, Iraq did not award Bai Hassan.

Over the course of the years since the signature of the contracts, Iraq has already revised twice the country’s production target. At the time of the four bid rounds, Iraq had envisaged to reach 12 million barrels per day of oil output capacity by 2018. Now, the general goal, revised the last time in 2015, is to have a production of 5.6 million to 6 million barrels per day by 2020. A first revision occurred in 2014 when the production target was moved to about 8.4. million to 9.0 million barrels per day by 2020. In this regard, the plateau revisions in Rumaila’s contract are quite emblematic. When the contract was signed in 2009, the plateau was set at 2.85 million barrels per day. Then, in 2014, the plateau was reduced to 2.1 million barrels per day by 2020. Finally, in October 2017, it emerged that BP was again in discussions with the Ministry of Oil over the output levels at Rumaila, which is currently producing 1.5 million barrels per day. At Rumaila, the additional problem is that the main reservoir declines at a rate of 17% every year so that BP needs to add 250,000 barrels per day every year to just maintain the present production level. Apart from Rumaila’s T.S.C., some other contracts have been amended since signature, but the nature of the amendments has not been made public.

The idea of organizing a fifth licensing round with improved fiscal terms for the I.O.C.s was on the radar of the Ministry of Oil already in the summer of 2012. However, after five years and half, this fifth licensing round or direct negotiations between the Ministry of Oil and the I.O.C.s with no auction have still to materialize. Over this period, the Ministry of Oil has announced at least three times its intention to put on offer some additional oil and gas fields. The most recent line of action dates to July 2017 when the Ministry of Oil announced the launch of a new project (it’s called the “Project”) to explore, develop, and produce nine onshore and offshore exploration blocks in south and middle Iraq near the borders with Iran and Kuwait. Also in this case, according to the Ministry of Oil, there is the willingness to modify the fiscal terms with the collaboration of the I.O.C.s as well. The official timetable calls for the submission of bids and awards at the end of June 2018.

Five out of the nine blocks included in this project are in Basra Governorate. They are the three blocks Khudher Al-Mai, Jebel Sanam, and Al Fao on the Kuwaiti border, the Sindibad block (including the Sindibad oilfield, which is jointly owned by Iraq and Iran, and which could have 3 billion barrels of recoverable oil) along the Iraqi-Iranian borderline, and the Arabian Gulf block in the Arabian Gulf. The other four blocks are in four different governorates, all on the Iraqi border with Iran. The Naft Khana block is in Diyala Governorate, the Zurbatiya block is in Wasit Governorate, the Shihabi block straddles between Wasit Governorate and Missan Governorate, and the Huwaiza block is in Missan Governorate.

RECOMMENDATIONS FOR IMPROVING THE FISCAL TERMS

When we analyze Iraq’s oil sector, one point is quite clear: in comparison to other OPEC members, Iraq’s reserves/production ratio has always been quite high—at the beginning of 2017, Iraq’s Ministry of Oil declared that the country’s proven reserves had increased to 153 billion barrels from a previous estimate of 143 billion barrels. This means that, on a proportional basis, Iraq has always had a production lower than that of many other OPEC members. So, logic would require that Iraq increase its oil production, if the country wants to fully benefit from its oil endowment. And, to obtain this target, it is important to improve the fiscal terms of the current and the future oil and gas contracts so that both the government and the I.O.C.s might obtain a higher profitability.

Rather than completely change the terms of the T.S.C.s, it appears now that the federal government intends to make some adjustments to the current contractual framework—incentivizing cost control will be a priority, but it seems that the Ministry of Oil is thinking of reducing the cap on the amount of admissible cost recovery and remuneration to a fixed dollar amount.

In specific, the T.S.C.s’ revised fiscal terms will have to address these two main points:   

  • Lack of Cost Efficiency — There is no alignment between the government and the I.O.C.s on obtaining the lowest costs per barrel. So, if the I.O.C.s have higher costs, they will have more oil costs to recover the incurred costs, and consequently their remuneration per barrel will be higher. In practice, this means that the I.O.C.s will obtain higher net revenues when costs are higher; no cost efficiency from the side of the I.O.C.s.

  • The I.O.C.s’ Income Is Not Sensitive to the Price of Oil  The remuneration fee depends on an R-factor (the ratio of cumulative cash receipts to cumulative expenditures in the conduct of the petroleum operations), but it’s fixed according to the envisaged thresholds, so the remuneration fee is delinked from the oil price. In practice, the Iraqi T.S.C.s are attractive to the I.O.C.s with low oil prices because they have a guaranteed fee per barrel (and the companies will obtain more in-kind barrels from the government to pay the remuneration fee when oil prices are low). Instead, the Iraqi T.S.C.s are relatively unattractive to the I.O.C.s with high oil prices because the remuneration fee is fixed (in this case, the added profitability goes all to the government; plus, the I.O.C.s reduce investments exactly when the government would like to expand production). 

There is an enormous variety in the way governments and the I.O.C.s may structure their petroleum contracts, but every one of the arrangements has different pros and cons. Today, throughout the world there is no specific fiscal system getting more ground, although we are witnessing some new fiscal solutions. The starting point of all the petroleum contracts is that the more attractive the resource base is, the tougher will be the fiscal terms. However, the beginning of the exploitation of unconventional oil and gas resources since 2009 has brought about a reduction in government take. On a global scale, old service contracts show a poor alignment of governments’ goals with I.O.C.s.’ goals.

The main general recommendations (general because more research is needed to produce a step-by-step plan of action) to develop T.S.C.s with improved fiscal terms are

  • Providing the T.S.C.s With More Flexibility – Indeed, the signed T.S.C.s have the same structure, but, in the end, they vary considerably along a variety of dimensions, such as, scope of the agreement, remuneration fee, plateau, other terms of the contract, assumptions about international markets prices, and so on. Unless the model T.S.C. is more flexible in accommodating all these different parameters, it is difficult to continue with a single model. The present T.S.C.s are probably too simple.

  • Rethinking the R-Factor Effects — Under the present T.S.C.s, if the I.O.C.s incur an additional expenditure, this expenditure will result in lowering the R-factor (in fact, an additional cost increases the value of the denominator in the R-factor ratio) in addition to the reduction in government income because of the reduction in the net revenue share. And, of course, a reduction in the R-factor will increase the losses for the government.

  • Considering Oil Price Fluctuations The present T.S.C.s do not consider oil price fluctuations; remuneration fees are fixed even if oil prices experience a dropdown of more than 50%. Under high oil prices, the present T.S.C.s are unattractive to the I.O.C.s while under low oil prices they are attractive.   

  • Finding incentives to Oblige the I.O.C.s to Be More Cost Efficient — According to the present T.S.C.s, if the I.O.C.s have higher costs they will recover more petroleum costs (in other words, the per barrel remuneration will be higher). Right now, for the I.O.C.s there is an incentive to spend more. 

  • Introducing the Effect of Inflation — The present T.S.C.s are not adjusted for inflation. So, if during the 20-year term of the T.S.C.s, significant inflation happens in the United States, the value of the per-barrel fee in real terms would quickly decline.

  • Considering the Introduction of a System Based on a Lower Net Revenue Share and a Flexible Royalty (Van Meurs, 2017) — In order to encourage efficient operations, the net revenue sharing rate should not exceed 60% to the government. The flexible royalty might be based on three different royalties: one royalty rate based on the daily field production, adjusted also for oil gravity and well depth; one royalty rate based on the oil price at the delivery point; and one royalty rate based on well productivity. This system could permit good returns at the same time to both the government and the I.O.C.s under different oil-price scenarios and provide strong incentives for the I.O.C.s to reduce costs.

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Flexible Royalty Formula — Source: Pedro van Meurs, “What Suggestions for an Iraq Single Fiscal Model for Upstream Petroleum,” April 2017 

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