wrapping up volume five 2010...integrity, and initiate and develop original research. • instill...

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Arab Petroleum Investments Corporation

الشركة العربية لالستثمارات البتروليةment

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Wrapping up Volume Five 2010

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APIC

December 2010

Economic Commentary

Volume Five 2010

© Arab Petroleum Investments Corporation /31 Comments or feedback to aaissaoui@apicorp‐arabia.com

We will measure our success by our ability to be recognized as [...] a

leading source of research on the Arab hydrocarbon and

energy industries.

(Excerpt from APICORP’s Mission & Vision Statement)

Front cover i l lustrations: Meaning and credit. APICORP’s logo is a Möbius strip. In their simplest form, such strips are largely used as a recycl ing symbol (a three‐pointed star forming an unending loop). The Corporation’s founding fathers thought of APICORP as a policy instrument for “recycling” their net savings into the development and transformation of a nascent petroleum industry. Although a l itt le more elaborate than the universal recycling symbol, which was adopted by the IMF in the 1970s, APICORP’s Logo has been kept simple for easy and definite recognition.

More intricate forms of the Möbius strip can be generated by computer. The ones i l lustrating the front cover of this document have been produced by math Ph.D. student Nate Berglund (www.math.gatech.edu/~berglund).

Economic Commentary

Volume Five 2010


Foreword

Restating the Foundation and Purpose

Introduction

As with previous editions this annual compilation assembles into one single volume – the fifth of its kind ‐ all issues of APICORP’s Economic Commentary published during 2010. The aim is to recapitulate key highlights drawn from APICORP research activities. In addition, we expect the compilation to provide a concrete sense of our efforts that can help take stock of progress as we prepare for another challenging year.

The launch issue of the Commentary (Issue No. Zero, dated December 2005), consisted of a modest one‐page “commentary on oil price and interest rate movements” – the two key determinants of APICORP’s business environment and profitability. The Commentary has since expanded into a more comprehensive piece reflecting the increasing sophistication of our research work.

Sources of support

In the course of its progress the publication has benefited from valuable comments and feedbacks from APICORP’s executive staff members and the wider readership around the world. The latter was made possible by the concurrent publication of several issues in the Middle East Economic Survey, which has given the Commentary a broader reach and greater impact.

Obviously, the publication would not have been viable without the research efforts, dedication and commitment of Mr. Ali Aissaoui, APICORP’s Senior Energy Economist Consultant and former Head of Economics and Research.

Principles and ambitions

As we embark on Volume 6, the principles and ambitions that underpin our research efforts and publications are worth restating and highlighting.

Foundation • Demonstrate intellectual independence and

integrity, and initiate and develop original research.

• Instill confidence to help realize the Corporation’s potential.

Purpose • Be an additional tool of business environment

scanning. • Be a vehicle for disseminating our research

findings . • Be trusted to add value to the region’s policy

debate.

Audience • Energy economists, professionals in the business

sector, and academics with potential interest in our region’s political economy.

• Policy analysts and policy makers .

Content • Global and regional insights relevant to

APICORPs footprint and business focus: o Macro‐economic environment. o Evolution of relevant industries and

markets. o Energy investment trends.

Methodology • Timely and analytical review of:

o Internal research projects, studies and analyses.

o Critically assessed external research findings.

Language • Concise, clear and accessible to a wide audience. • Jargon‐free even when dealing with intensely

academic arguments.

Ahmad Bin Hamad Al‐Nuaimi APICORP’s Chief Executive and General Manager

Economic Commentary

Volume Five 2010


Content

Page Foreword – Restating the Foundation and Purpose

3

Summary of Issues

5

Issues Vol 5 No 1‐2 APICORP’s Annual Review of the Arab Economic and

Energy Investment Outlook ‐ A Dim Light at the End of a Long Tunnel

8

Vol 5 No 3 To What Extent Has the Global Financial Crisis Reshaped Our Perception of the Energy Investment Climate in the Arab World?

12

Vol 5 No 4 On Being Fair, Beautiful and Nearly Perfect: A Reflection On The Ethics, Economics And Politics Of Oil Prices

15

Vol 5 No 5 The Arab Energy Investment Outlook in a Changing Landscape ‐ A Summary of APICORP’s Report to the 9th Arab Energy Conference (Doha, 9‐12 May 2010)

18

Vol 5 No 6‐7 Macondo and Global Oil Supplies and Prices

19

Vol 5 No 8 Finding A Needle In the Dodd‐Frank Haystack And Wondering What To Expect From It ‐ Our Readers Warn Of The Unintended Consequences Of The ‘Disclosure Of Payments By Resource Extraction Issuers’

21

Vol 5 No 9 Joint Report to the G20 on Energy Subsidies: A Critical Review

23

Vol 5 No 10‐11 Vol 5 No 12

MENA Energy Investment Outlook: Recovery Despite Uncertainty MENA Natural Gas: A Paradox of Scarcity Amidst Plenty

25

28

Economic Commentary

Volume Five 2010


Summary of Issues

Vol 5 No 1‐2, January‐February 2010: APICORP’s Annual Review of the Arab Economic and Energy Investment Outlook ‐ A Dim Light at the End of a Long Tunnel

The global financial crisis and the subsequent turmoil in the oil markets have combined to take a toll on the region’s macroeconomic and energy investment outlooks. To cope with this dual crisis, Arab energy policy makers and project sponsors have had little option but to reassess their investment strategies and scale down projects portfolios. As a result, the uptrend momentum achieved in recent years has reversed. This review for the 5‐ year period 2010– 14 revealed a lower potential capital investment, which stems largely from the postulation of subdued project costs. The review also confirmed a further drop in actual capital requirements as a consequence of the continuing shelving and postponement of projects that are no longer viable. Furthermore, although the overall capital structure of the remaining projects has slightly shifted to equity, the downstream industry remains highly leveraged. In a context of higher risk aversion and tighter credit conditions, securing the appropriate amount and mix of debt is likely to be considerably more challenging than any time before. Vol 5 No 3, March 2010: To What Extent Has the Global Financial Crisis Reshaped Our Perception of the Energy Investment Climate in the Arab World?

APICORP’s perceptual mapping of MENA energy investment climate has provided a unique pre‐ and post‐financial crisis snapshots of the energy investment climate of the fifteen Arab petroleum‐producing countries. The changes captured in this way range from Saudi Arabia getting nearer to the “ideal point” benchmark, to a significant deterioration of the positioning of Sudan, Mauritania and Yemen. In between, the remaining countries are in three groups in contrasting situations: a) while maintaining their strong positions, Qatar, the UAE and Kuwait have moved apart from each other with Qatar widening its lead; b) both the clusters formed of Oman, Bahrain and Tunisia, and that formed of Libya, Algeria and Egypt (to which Syria

could be added) are in neither a better nor a worse position; c) Iraq has made a positive transition: though still very far from the ideal point, its location on the map is getting much better. Vol 5 No 4, April 2010: On Being Fair, Beautiful and Nearly Perfect: A Reflection On The Ethics, Economics And Politics Of Oil Prices

The permeation of ethics into the discourse about oil prices may be interpreted as a symptom of failure of both markets and policy making based on conventional economics. In the context of efforts by behavioral economists to provide a solid intellectual foundation to ethical principles, the characterization of oil prices in terms of fairness may be interpreted as indicating genuine concern for their detrimental economic effects on both petroleum exporting counties and energy importing countries.

Vol 5, May 2010: The Arab Energy Investment Outlook in a Changing Landscape ‐ A Summary of APICORP’s Report to the 9th Arab Energy Conference (Doha, 9‐12 May 2010)

APICORP’s report to the 9th Arab Energy Conference (Doha, 9‐12 May 2010) examines the prevailing state of both the credit market and the oil market and their effect on the Arab energy investment outlook. The report is in three parts: the first outlines the dimensions of the twin crises; the second assesses their macroeconomic impact; the third delves more deeply into their effects on the energy investment outlook. This Commentary condenses the report’s findings and highlights the main challenges ahead. It further outlines key policy recommendations.

Vol 5 No 6‐7, June‐July 2010: Macondo and Global Oil Supplies and Prices

The Macondo spill has cast a shadow on the development of one of the key sources of growth of petroleum. The incident is very likely to restrict deep offshore production and increase its cost, but not in a proportion that could affect significantly global supplies in the near term. As a result, oil prices are unlikely to

Economic Commentary

Volume Five 2010


move outside our anchor band of $70‐90 per barrel (OPEC basket price). Any longer term outlook must remain conjectural until we gain a better understanding of what precisely caused the incident and how energy policy makers and the petroleum industry are likely to deal with its aftermath.

Vol 5 No 8‐9, August‐September 2010: Finding A Needle In the Dodd‐Frank Haystack And Wondering What To Expect From It ‐ Our Readers Warn Of The Unintended Consequences Of The ‘Disclosure Of Payments By Resource Extraction Issuers’

The international readers of APICORP’s Economic Commentary have proved themselves to be a trustworthy and valuable source of analysis and inspiration. The overall impression from their remarks, which form the core of this commentary, is that of disappointment with a transparency law that is redundant and unnecessary. It appears that in seeking to hold the legal and ethical high‐ground, US legislators have unwittingly shot themselves in the foot. It is very likely indeed that US oil companies operating overseas will bear the brunt of the regulations put in motion. As for the resource‐rich countries, we believe that persuading, rather than coercing, them to fully adhere to the legitimate international charters, conventions and standards in place can be more conducive to better governance.

Vol 5 No 9, September 2010: Joint Report to the G20 on Energy Subsidies: A Critical Review

The IEA, OECD, OPEC and World Bank joint report to the G20 provides an insightful analysis and practical suggestions for tackling energy subsidies. Based on seasoned professional expertise, the findings and recommendations have been presented in a clear, coherent and logical sequence of steps focused on defining, measuring, reforming and implementing. Yet, key recommendations are bound to be divisive and some of them, such as the “country‐specific” approach, may carry the seeds of their own failure.

Vol 5 No 10‐11, Oct‐Nov 2010: MENA Energy Investment Outlook: Recovery Despite Uncertainty

Notwithstanding an uncertain global economic climate, growth of energy investment in MENA region is expected to resume, mostly driven by the power generation sector. In this context project sponsors face

many of the same challenges: cost uncertainties, feedstock availability and funding accessibility, with the latter remaining the most critical. Due to global economic conditions, public resources have been inadequate and private investment has somewhat retreated. As a result, MENA governments face a difficult balancing act. They must step up to fill the current funding gap, but they must also provide the assurances critical to regaining private investment momentum.

Vol 5 No 12, Dec. 2010: MENA Natural Gas: A Paradox of Scarcity Amidst Plenty In view of a paradox of scarcity amidst plenty, this commentary offers valuable empirical insights into the potential of MENA natural gas endowment by taking a closer look at both reserves and resources. On aggregate, proved reserves are substantial and their dynamic life fairly long. However, acceleration of depletion appears to have reached a critical rate for more than half our large sample of countries. If production continues not to be replaced in Algeria, Bahrain and to a lesser extent Iraq, this could lead to a supply crunch, obviously sooner for Bahrain than later. Oman, Syria and Tunisia would face a similar prospect in the absence of imports via respectively the Dolphin Pipeline (Qatari gas to the UAE and Oman), the Arab Gas Pipeline (Egyptian gas to Jordan, Syria and Lebanon), and the transit pipelines to Europe (Algerian gas to Tunisia and Morocco en passant). Furthermore, the supply patterns of the UAE, Libya, Saudi Arabia and Kuwait have reached a tipping point that should trigger urgent actions to curb demand. The extension of the analysis to undiscovered resources and inferences from assessed to non‐assessed provinces has underscored a higher aggregate potential for reserve expansion than commonly assumed. On a country basis the resulting opportunities for E & D appear to be the greatest for Saudi Arabia and Iran, followed by Qatar, Iraq, the UAE, and Algeria. To a lesser extent, opportunities seem to be also present in Oman, Jordan, Libya, Yemen and Egypt. As these opportunities will be shifting towards unconventional gas, they will entail significantly higher costs of finding and development. Faced with structurally lower net‐back prices, MENA gas‐exporting countries have little choice but to raise domestic prices as part of a more conducive climate for investment and re‐investment. Obviously, this is even more so the case for the non gas‐exporting countries.

Economic Commentary

Volume Five 2010


Issues

Economic Commentary

Vol 5 No 1-2, Jan-Feb 2010

© Arab Petroleum Investments Corporation Page 8/31 Comments or feedback to: aaissaoui@apicorp‐arabia.com

APICORP’s Annual Review of the Arab Economic and Energy Investment Outlook

A DIM LIGHT AT THE END OF A LONG TUNNEL This commentary has been prepared by Ali Aissaoui, Senior Consultant at APICORP.

1. The year 2009 saw the global financial crisis spread far beyond its US roots to engulf the rest of the world. By throwing the global economy into a deep and protracted recession, the crisis has precipitated the collapse of oil markets and prices and cast a shadow on the Arab growth outlook. For a region whose main economies rely predominantly on petroleum exports, one crisis has followed on the heels of another. The sharp contraction of credits has been compounded by a dramatic fall in corporate cash flows and government fiscal petroleum revenues to severely constrain funding. Even if both the credit market and the oil market have stabilized in recent months, it is unreasonable to believe that the region’s troubles are over. Serious delayed effects, such as those experienced by Dubai, may yet occur. As insightfully noted by Mohamed El‐Erian in this regard, “[the global] financial crisis was a consequential phenomenon whose lagged impact is yet to play out fully in the economic, financial, institutional and political arenas.”

1

2. At the heart of the new challenges facing the Arab world, as it strives to mitigate the shocks and aftershocks of these crises, is how to maintain its capacity to make a major contribution to the world’s energy supply, particularly as its growth potential is still far from being realized. The region’s holds 54 percent of the world’s proven reserves of crude oil and condensate, but only contributes to 33 percent of global oil output. Similarly, while it contains 30 percent of proven natural gas reserves, it only accounts for 15 percent of total gas output. However, in times of crisis expediency becomes a necessary course of action: scaling down energy investment plans by making key projects redundant has been inevitable.

3. This commentary reviews the state of the global economy and the oil markets and their effect on the Arab economic and energy investment outlook. The analysis is in three parts: Part One exposes the fragility of the global recovery, the extent oil markets have stabilized and the downside risks to Arab growth. Part Two highlights the region’s continuing shrinking energy investment outlook. Part Three outlines the more challenging environment facing energy policy makers and project sponsors.

A still‐fragile recovery

4. Despite the recession loosening its grip, the outlook for the global economy remains clouded with uncertainty. As traditional economic paradigms have been challenged by the financial crisis, economists have had hard time to produce reliable forecasts . They were first mostly “behind the curve”, i.e. unable to anticipate events, then “ahead of the curve”, i.e. indulging in voluntary optimism. The IMF macroeconomists, for instance, went through three revisions of their October 2008 forecasts before acknowledging the depth of the global recession (April

1 Mohamed El‐Erian, “Dubai: what the immediate future holds”, Daily Telegraph, dated 29 November 2009.

2009). Later, in July, then in October 2009, they declared that the recovery was in sight. Their underlying assumption of a “V‐shaped” global recession, which is well reflected in Figure 1 (grey zone), stems from the belief that the strong and coordinated monetary, fiscal and financial policy responses around the world have been effective. According to the their October 2009 outlook, these responses have supported demand, decreased uncertainty, and minimized systemic risk in financial markets. At the time of releasing this commentary, the IMF revised further upward its forecasts for 2010 and concluded that the global economy was on a faster track to recovery.

2 It put growth in advanced economies at 2 .1 percent, and growth in emerging markets and developing countries at 6.0 percent, both translating into a robust 3.9 percent growth for world output. However, the IMF’s key prerequisite is that “due to the still‐fragile nature of the recovery, fiscal policies need to remain supportive of economic activity in the near term, and the fiscal stimulus planned for 2010 should be implemented fully.” (Ibid.)

Figure 1: Regional Growth Impact of the Twin Crisis

‐4.0

‐2.0

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APICORP Research Source: IMF, WEO Oct 2009 and 26 Jan 2010 updateand own compilation and forecast for the Arab world

The rise, fall and stabilization of oil prices 5. The way the financial crisis and the consequent global recession have impacted oil markets is far from simple or straightforward. To be sure, the oil price bubble formed in the summer of 2008, when oil prices reached an all time intra‐day high of $147 per barrel on the New York Mercantile Exchange (Nymex), could not be sustained. It was believed, up to then, that the increasingly heavy involvement of institutional investors, which sought to diversify their asset portfolios into commodities as a hedge against inflation and a weaker dollar, has led to serious market dislocations. Their positions have grown so large that they distorted prices in the futures markets. In this context, both the Organization of the Petroleum Exporting Countries (OPEC) and the U.S. Commodity Futures Trading Commission (CFTC) refrained from drawing boundaries of tolerable market behavior. Instead, they indulged into a sterile debate over whether speculation or fundamentals were driving up oil prices. Central to this controversy was the concern

2 “IMF Revises Up Global Forecast to Near 4% for 2010”, IMF Survey Magazine online, 26 January 2010.

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Economic Commentary



that neither institutions wanted to be held responsible for the surge in oil prices. As international pressure mounted, however, Saudi Arabia squeezed its thin spare capacity – too thin at that time ‐ to cushion the physical market with extra oil for which there was no demand. Simultaneously, but on a different plane, CFTC focused its scrutiny on swap dealers and commodity index traders in a move to shed light on the activity of investment banks and improve transparency and control of the futures market. With some success : the burst of the bubble led to prices falling under $35 per barrel the following winter. But this was steeper than oil market analysts’ anticipations and far lower than oil producers’ expectations.

Figure 2: OPEC Output Cuts: Setting a Floor to Oil Prices

30

50

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130

150

Jan‐08

Apr‐08

Jul‐08

Oct‐08

Jan‐09

Apr‐09

Jul‐09

Oct‐09

OPEC Re

ference Ba

sket Pric

e ($/bbl)

OPEC's outputcut (mmb/d)

Bursting of theSummer 2008oil market bubble

0.5

2.21.5

APICORP Research Source: OPEC monthly ‐ Dec 2009

Stabilization around the Saudi $75/bbl "fair price"

6. The collapse of oil prices threw OPEC into crisis management mode . Cutting output three times between September 2008 and February 2009, the Organization managed to set a critical floor of $40 per barrel for its reference basket price (Figure 2). A fourth cut has finally not been implemented as prices stabilized around the Saudi $75 per barrel “fair price”. As the world’s biggest oil producer and holder of the largest spare capacity, Saudi Arabia plays a critical role in balancing global supply and demand. As such, it exerts considerable influence on international oil markets, including the ability – as long as its spare capacity is perceived as ample enough ‐ to anchor market expectations. Not unexpectedly, since the early summer of 2009 oil prices have tended to be contained within a range of $60 to $80 per barrel, which we have established to be at the confluence of the breakeven price of petroleum projects in frontier areas and the price needed to ensure producers’ long‐term fiscal sustainability. 3

Downside risks to Arab growth 7. As long as the oil market was uptrend, up to mid‐2008, the Arab world was thought to be spared from the financial crisis. However, the subsequent steep fall in oil prices highlighted previously, and the tightening of credits have combined to take a toll on the region’s economy. Growth, whose average during the 5‐year period preceding the financial crisis was 5.2 percent, has contracted sharply to 2.1 percent in 2009 (Figure 6). As

3 This price range has been conceptualized and extended by Ali Aissaoui in “GCC Oil Price Preferences: At the Confluence of Global Energy Security and Local Fiscal Sustainability,” Energy Security in the Gulf: Challenges and Prospects (ECSSR: forthcoming, 2010); proceedings of the ECSSR 15th Annual Energy Conference, Abu Dhabi, November 16–18, 2009.

noted earlier, the IMF raised its forecast for the region (as re‐compiled by ourselves) to 3.5 percent for 2010 (Figure 1), despite the near absence of growth in the UAE as a result of the "drag" of Dubai’s real estate sector. The extent to which the region’s growth will recover, and reach the high rates experienced in the pre‐crises period, depends on key countries maintaining a certain level of public expenditures and the limits of their fiscal sustainability. In this regard, the major risk to the medium term Arab economic outlook is a weak and protracted global recovery, which would keep downward pressure on oil prices and governments’ fiscal revenues. Other risks to the outlook include delayed effects of the crisis of the sort experienced by Dubai. On a far more severe level, heightened geopolitical threats should not be discounted either. Whatever the growth scenarios for the Arab world, however, inflation and unemployment, whose relative importance has been reversed, will continue to top the region’s socio‐economic policy agenda.

A Continuing shrinking Investment Outlook

8. To cope with these far‐reaching crises, Arab energy policy makers and project sponsors have had little option but to reassess their investment strategies and scale down projects portfolios. Figure 3, which summarizes the key findings of our successive annual rolling five‐year reviews, shows that the uptrend momentum achieved in recent years has reversed. Indeed, the current (seventh) review for the five‐year period 2010–14 points to lower capital investment potential. It also confirms a further drop in actual capital requirements. At the present time, we expect the capital investment potential to decrease by nearly 15 percent, to US$470 billion, and the actual capital requirements to fall by some 29 percent below this potential, to $335 billion.

Figure 3: Rolling 5‐year reviews of Arab energy investments ,

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2005‐09 Review

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2010‐14 Review

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Apparently shelved (LS)

Actual requirements (LS)

"Average project cost" index (RS)

Cost assumption index (RS)

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9. Closely reflecting the distribution pattern of crude oil and natural gas reserves in the region, 70 percent of the energy capital investment potential continues to be located in five countries namely Saudi Arabia, Qatar, the UAE, Algeria and Kuwait, with more than half this potential in the first three (Figure 4). In Saudi Arabia, potential capital investments have come down to $139 billion. Shelved or postponed projects are estimated at 21 percent of this potential, mostly in the refining and petrochemical sectors. In Qatar the potential capital investment is now estimated at US$62 billion. In this country, we assume that the moratorium on further development of the

Economic Commentary



North Field gas reserves will not be lifted during the review period. As a result, shelved and postponed projects are put at a higher rate of 42 percent of potential. In the UAE the revised potential capital investment totals US$51 billion with projects made redundant amounting to 16 percent. In Algeria postponed projects represent some 18 percent of the revised potential investment of US$38 billion. Finally, Kuwait, which exhibits the same revised investment potential than Algeria, has by far the highest rate of postponed and shelved projects. This, however, has more to do with the dynamics of domestic politics and policy than the effect of the credit and oil market crises. In this context, it is difficult to estimate the country’s actual capital requirements as long as major upstream projects such as “Project Kuwait” ‐ a US$55 billion investment program ‐ remain at a standstill, or key downstream projects such as the US$15 billion Al‐Zour refinery of 615,000 barrels‐per‐day capacity, are undecided.

Figure 4: Geographical Pattern of Total Energy Investments

0 30 60 90 120 150 180

Mauritania

Lebanon

Jordan

Sudan

Morocco

Tunisia

Yemen

Bahrain

Syria

Iraq

Libya

Oman

Egypt

Kuwait

Algeria

UAE

Qatar

Saudi Arabia

US$ billion

Actually in progress Apparently shelved

APICORP Research

10. The above five‐country highlight is dictated more by ranking expediency than by the assumption of particular uncertainties. Equally notable in terms of frustrated effort are the constraints faced by countries such as Oman, Egypt, Libya and Iraq. More specifically in Iraq, where the ambitions to achieve the full development of the oil sector have been revived, the extent of foreign investors’ contribution will depend on the government’s ability to provide an ultimate solution to recurrent security problems. Furthermore, when considering all the significant energy‐investing countries, a further important aspect to highlight is that the investment outlook is affected across the board. In the non petroleum‐producing countries energy investments are concentrated in a chronically under‐developed power sector. While all sectors of the industry are facing the same funding challenges, in the power and power/water sectors the key test is the extent the burden of financing new generation capacity can continue to be shifted to the private sector, both of which are examined next.

A more challenging funding environment

11. On top of the challenges facing the Arab energy sector is funding. In a context of the credit and oil market turmoil, a marked shift in projects’ capital structure has exacerbated the dilemma facing corporate financing policies . Indeed, we have witnessed a trend towards a more equity‐ oriented capital

structure. The industry normally uses retained earnings (internal equity) to fund high risk, high return upstream and associated midstream activities. In contrast, it tends predominantly to use debt and external equity for low risk, low return downstream activities. Based on most recent deals, the average equity–debt ratio in the oil‐based refining/petrochemical sectors has been 35:65. The ratio in the gas‐based downstream sector has been 40:60 to factor in higher risks of feedstock availability. In the power and power/water generation sectors private investors used to target much higher equity‐debt ratios, up to 10:90, in order to enhance their returns on equity. Nowadays, the overall ratio for this sector has been reset to 30:70 to reflect a lower leverage of independent power and power/water projects (IPPs/IWPPs). As private investors may not be able to afford neither a higher equity stake nor the higher cost of long‐maturity financing, we should expect a lower share of IPPs/IWPPs in the potential capital investment; much lower than the 40 percent found in the last review. 4

12. On this basis, the resulting weighted average capital structure for the whole oil and gas supply chain is likely to be 55 percent equity and 45 percent debt for the period 2010–14 (Table 1). This compares with the equity–debt ratios of 50:50 found in the pre‐credit crisis review for the period 2008–12.

Table 1: Potential Capital Requirements and Assumed Capital Structure

US$ billion Percent Equity Debt

Oil supply chain . Upstream 70 15 100% 0% . Midstream 10 2 100% 0% . Downstream 140 30 35% 65%Gas supply chain . Upstream 45 10 100% 0% . Midstream 15 3 100% 0% . Downstream 110 23 40% 60%Power/Water link . Generation 80 17 30% 70%Total Investments 470 100 55% 45%

APICORP Research

Potential capital

requirements

Assumed capital

structure

13. Whatever the trend in capital structure is, however, achieving the needed amount and mix of equity and debt will be considerably more challenging . On the one hand, we have estimated that a prolonged period of low oil prices below $60 per barrel will affect project sponsors’ ability to self‐ finance upstream investments. As noted earlier, $60 per barrel is the lower bound of a price band that lies at the confluence of the economic price needed to develop projects in frontier areas and the fiscal price needed to meet oil producers’ realistic requirements for revenues. This level of price will limit the amounts of corporate retained earnings, restricting as a result self‐financing. On the other hand, funding prospects for the still highly leveraged downstream will be even more daunting. The annual volume of debt would be in the range of US$30 billion to $42 billion for the next five years. The lower bound results from the actual capital requirements found in the current review and the likely capital structure highlighted above. The higher bound corresponds to the potential requirement and the speed at

4 For a thorough analysis of the outlook of the power sector in the Arab world see Ali Aissaoui, “Powering the Arab Economies in a New, More Challenging Environment”, MEES dated 25 January 2010.

Economic Commentary



which redundant projects will be brought back when the business climate improves. A median amount compares to the all‐time annual record of US$38 billion achieved in the loan market prior to the onset of the global credit crisis (Figure 5). Nowadays, such amounts of debt can hardly be met owing to lesser credit availability, higher costs of borrowing and tighter lending conditions. And this is despite the move by some Arab public investment funds to tap governments’ net savings and step up their lending and involvement in the local debt market as has been the case in Saudi Arabia in particular.

Figure 5: Project Financing Loans to the Arab Energy Sector

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Loans' all‐in pricing

(Bps above Libor)

Loans (US$ billion)

Energy project finance loans (US$ billion) All‐in pricing above $Libor (Bps)

APICORP Research usingDelaogic Loanware database2009*: Provisional

2010**: Own estimations (tentative)

Impact of the

war on Iraq

Impact of the

credit crisis

Investment climate 14. In this context, and more than any time before, projects’ and companies’ credit ratings, which are almost always capped by sovereign limits, will be closely scrutinized. However, not every country has a sovereign rating. Of the fifteen Arab petroleum‐producing countries, only nine have solicited one and just eight of them have managed to attain investment grade. The fewer countries in the GCC area, namely Kuwait, Qatar, Saudi Arabia and the UAE, whose rating has been maintained at AA‐ by Standard and Poors (S&P) ‐ or equivalent ratings by other credit rating agencies (CRAs) ‐ will be able to achieve relatively lower borrowing cost and better lending terms (Table 2).

Table 2: Arab Countries’ Sovereign Ratings (Long Term, Foreign Currency; nr: not rated)

Rated countries S&P Moody’s Fitch

Kuwait AA‐ Aa2 AA

Qatar AA‐ Aa2 nr

Saudi Arabia AA‐ A1 AA‐UAE nr

1 Aa2 nr2

Bahrain A A2 A

Oman A A2 nr

Libya nr nr BBB+

Tunisia BBB Baa2 BBB

Morocco BB+ Ba1 BBB‐

Egypt BB+ Ba1 BB+

Jordan BB Ba2 nrLebanon B B2 B‐Sp

ecu

lative

APICORP Research ‐ Compiled from CRAs ‐ December 2009

1 Abu Dhabi (AA) and Ras Al Khaimah (A) ‐

2 Ras Al Khaimah (A)

Investment grade

15. To complement the above limited number of sovereign ratings, APICORP uses its own “perceptual mapping” of the energy investment climate that encompasses all Arab petroleum‐producing countries. This mapping, which combines three attributes (investment potential, country risk, and the enabling environment) shows an IDEAL POINT, which is the centre of gravity of the highest achievable scores (Figure 6).

Figure 6: Perceptual Mapping of the Energy Investment Climate

Vast investment potential

Limited investment potential

Highcountry risk

Lowcountry risk

Strong enablingenvironment

Weak enablingenvironment

KSA

UAEKUW

BAH

IRQ

MAUSUD

ALG

TUN

EGYLIB

SYR

YEM

OMA

IDEAL POINT

APICORP ResearchUpdated Dec. 2009

Investment grade

Speculative grade

Not rated

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QAT

16. Accordingly, Saudi Arabia (KSA) on the one hand, and the cluster formed of Qatar (QAT), Kuwait (KUW) the United Arab Emirates (UAE) on the other hand occupy the most desirable quadrant [Vast Investment Potential ‐ Strong Enabling Environment – Lower Country Risk]. They all appear nearest to the Ideal Point. Iraq (IRQ), which still appears far from this point, has in fact improved its position compared to previous scorings. The remaining countries are clustered relatively close together, with broadly similar perceived investment climates in each cluster. Despite the challenges highlighted earlier, the GCC area appears better placed to expedite project gestation and implementation and ensure a rapid resumption of energy investments, once the crisis is over.

Conclusions

17. The global financial crisis and the subsequent turmoil in the oil markets have combined to take a toll on the region’s macroeconomic and energy investment outlooks. To cope with this dual crisis, Arab energy policy makers and project sponsors have had little option but to reassess their investment strategies and scale down projects portfolios. As a result, the uptrend momentum achieved in recent years has reversed. Our current review for the 5‐ year period 2010– 14 has revealed a lower potential capital investment, which stems largely from the postulation of subdued project costs. The review has also confirmed a further drop in actual capital requirements as a consequence of the continuing shelving and postponement of projects that are no longer viable. Furthermore, although the overall capital structure of the remaining projects has slightly shifted to equity, the downstream industry remains highly leveraged. In a context of higher risk aversion and tighter credit conditions, securing the appropriate amount and mix of debt is likely to be considerably more challenging than any time before.

18. Although the credit and oil markets have stabilized, the speed at which redundant energy projects are likely to be brought back is still uncertain. The region’s investment recovery, will ultimately depend on the revival of global and domestic growth. Meanwhile, funding may not be fully restored yet. Not without lenders and investors being reasonably confident that severe delayed effects of the global financial crisis, of the sort experienced by Dubai, will continue to be contained should they happen again.

Economic Commentary Volume 5 No 3 March 2010

© Arab Petroleum Investments Corporation /31 Comments or feedback to: aaissaoui@apicorp‐arabia.com

To What Extent Has the Global Financial Crisis Reshaped Our Perception of the Energy Investment Climate in the Arab World?

This commentary has been prepared by Ali Aissaoui, Senior Consultant at Apicorp. It is adapted and updated from a research approach first implemented by the author in 2005. 1. Despite a voluntary optimism that the global recovery is taking hold, the Arab world still faces an uncertain outlook. In addition to a deteriorating geopolitical environment, the region continues to feel the lagged effect of the global financial crisis. The impact of the crisis, which has caused a marked slowdown of growth and investment, has worked mainly through external channels. Indeed, the credit crunch has reduced capital inflows while the ensuing global recession has led to a drastic fall of petroleum export volumes and prices. In this context, funding counter‐cyclical fiscal programs and maintaining liquidity in the domestic financial sector would not have been possible without some governments repatriating a significant portion of their net savings. These macroeconomic policy responses may, however, prove unsustainable should the global recovery falter.

2. Against this backdrop, this commentary examines the extent to which the above manifestations of the crisis have reshaped our perception of the energy investment climate in the Arab world. While we base our findings on a pre‐ and post‐crisis snapshot, we sought to avoid the “illusion of causality”, i.e. assigning causation to sequential events. The commentary is in three parts. Part One introduces the analytical tool used in this context, which consists of a “perceptual mapping”. Part Two examines how the crisis has affected the ranking of the countries using such attributes as country risk, enabling environment and investment potential. Part Three infers from a reading of the pre‐ and post crisis perceptual maps key changes and trends in country positioning.

Perceptual mapping in a nutshell

3. Perceptual mapping aims at determining the perceived relative image of a set of objects, such as consumer products, firms, countries, or even concepts and ideas. The similarities or differences between pairs of objects are transformed into distances represented in a multidimensional space. The resulting graphical representation is known as perceptual map. The map is constructed assuming a set of descriptive attributes.

4. The most common method for visualizing the pattern of proximities (similarities or differences) among a set of objects is Multidimensional Scaling (MDS). MDS allows the conversion of rankings in several dimensions, with each dimension corresponding to a distinct attribute. The method is fairly sophisticated and its application can prove complex and time consuming. In our case, however, where the attributes are limited to three, each object (country) is located using its centre of coordinates as a simplification. This is expected to coincide with the centre of gravity (CoG) or the mean coordinates of its attributes. The resulting map is a two dimensional representation of a 3‐D space (Figure 1). For reasons made clearer further below, countries are ultimately positioned in terms of their proximity (or remoteness) to an “ideal point”, which coincides with the center of gravity of the highest scores achievable on each attribute. The ideal point is used as a benchmark.

Figure 1: Object Location Using the Centre of Gravity (CoG) in a 3‐Dimension Space

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Objects and attributes

Objects 5. Our objects are countries. Normally, APICORP’s footprint is the Arab world, which consists of the 22 states of the Arab League. However, countries that matter most, in terms of energy investment, are about fifteen. They range from the world's largest strategic petroleum (oil and gas) reserves, i.e. Saudi Arabia and Qatar, to newcomers such as Mauritania, which have yet to confirm the extent of their recently discovered resources. Together they represent 83% of the region’s population, 93% of its aggregate GDP and the quasi‐totality of its proven petroleum reserves.

Attributes 6. Three attributes have been selected: country risk, enabling environment and energy investment potential. Each one is defined and quantified in turn on the basis of several more specific variables. This allows a simple, preliminary ranking based on a single criterion.

7. Country risk is defined as the perceived and/or measured change in the socio‐political and macro‐economic outlook that could interfere with a country’s contractual flow of investments. The Socio‐political outlook focuses on government stability and instability within the geopolitical context and its ability to gain approval of its reform program and the corresponding legislative and fiscal agenda in parliament or any other form of representation. The Macro‐economic outlook analyses trends in economic growth, unemployment, inflation, current account and fiscal balances, and the articulation and coherence of fiscal and monetary policies. The analytical framework for assessing and incorporating the socio‐political and macroeconomic outlooks into country risk factors are derived from APICORP’s internal country risk methodology.

8. Countries are rated taking into account the above categories of risks and compiling them into a composite country risk rating. Each component is assigned a maximum value (risk points) with the highest number of points indicating the lowest potential risk and vice versa. With the exception of the socio‐political risk assessment, which is fairly subjective, all other broad categories of risks are tentatively assessed on a quantitative basis. Using these metrics, Figure 2 shows the 15 countries’ relative ranking. Qatar, which has scored the same in both pre‐ and post‐crisis

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periods, continues to top the ranking. Libya, Sudan and, to a larger extent Iraq, have improved their ranking. In contrast, the ranking of the UAE has slightly deteriorated as a result of its revised macroeconomic outlook. In a much more dramatic way, Yemen’s uncertain socio‐political outlook has had the most effect on the country’s ranking. All other countries have somewhat managed to maintain their scores and relative positioning.

Figure 2: Country risk ranking

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Pre‐crisis country risk ranking

Post‐crisis country risk ranking

9. Enabling environment. The second attribute is the degree business in the energy sector is enabled. This is underpinned by petroleum/energy policies and the domestic financial environment. The key factors taken into consideration, in this regard, include each government’s vision, and the practical articulation of such a vision. In the financial sector, the key factors include the country’s financial structures, the degree of development and performance of the country’s capital market, as well as the extent to which the business climate in each country has been conducive to project financing.

10. As the above cannot be addressed with precise analytical methods, a two‐step Delphi technique has been used to determine the degree of business enabling in each of the 15 countries. Delphi aims at structuring an information process within a panel of experts. The process involves that the panel ‐ individually and collectively ‐ returns the best‐informed opinion and insight on the following:

The degree of clarity of governments’ statements on national energy policy;

The institutional, legal and fiscal framework governing the petroleum and energy industries;

The domestic banking and capital market environment.

More specifically, the Delphi panel has been guided by the following questions:

Is the government’s energy vision clearly stated?

How well is it articulated into principles, objectives and strategies?

Are policies translated into comprehensive and good quality legal, fiscal and institutional framework?

Has the country got a sovereign credit rating and, if so, how it has evolved?

How developed are the domestic financial and capital markets?

Is the energy sector ripe for project financing (meaning non or limited recourse financing)?

To what extent has the domestic financial sector been affected by the global crisis?

11. This exercise has resulted in the classification illustrated in Table 1. The relative positioning along this dimension is taken by reference to Qatar which has been assigned the highest score.

Table 1. Enabling Business Environment Ranking (Delphi) Positioning 10.0 9.7 9.7 9.1 8.8 7.9 7.9 7.0 6.4 5.8 4.5 3.9 3.6 3.3 3.0

Qatar

KSA

UAE

Bahrain

Oman

Kuwait

Tunisia

Egypt

Algeria

Libya

Syria

Iraq

Sudan

Mauritania

Yemen

Statement of

national energy

policy

9 7 8 7 8 6 7 7 8 6 5 6 4 3 3

Institutional,

legal and fiscal

framework

8 7 8 7 7 6 7 6 7 5 4 3 4 4 3

Banking and

capital market

environment8 9 8 8 7 7 6 5 3 4 3 2 2 2 2

Each country is displayed with three sub‐rankings. Severely constrained policy frameworks appear in different shades of red, with the low‐end‐point being today’s Yemen. In contrast, greatly enhanced frameworks appear in different shade of green, with the high‐end‐point being today’s Qatar. In between, it is interesting to note the contrasting cases of countries such as Algeria and Kuwait. Algerian energy policies and the associated institutional, legal and fiscal framework continue to be perceived as relatively more appealing (green shades) than the country’s financial structure and performance (red shade). To some extent the opposite can still be observed in the case of Kuwait, though in a less dramatic way. Otherwise, except for Saudi Arabia (improvement) and Yemen (deterioration) all other countries have maintained their relative ranking, compared to the pre‐crisis Delphi. Even the UAE, whose enabling environment seems to have been slightly affected by the delayed impact of the crisis on Dubai, has maintained its third rank.

12. Energy investment. The third attribute is the energy investment in each of the 15 selected countries. A distinction is made between investment and investment potential. Normally, investment is a function of anticipated demand, which underpins the industry’s growth, and the amount of additional production capacity needed to accommodate that growth. Such an investment is constrained by a number of factors, including precisely country risk and the enabling environment. In contrast, investment potential should be an unconstrained function of assets. In this sense a clearly defined and easily quantifiable indicator of investment potential is the combined proven oil and gas reserves of each of the 15 countries. Because the financial crisis and ensuing global recession have quasi‐uniformly affected investment across countries, we focus on investment potential.1 The relative positioning along this dimension is taken by reference to Saudi Arabia which has been assigned the highest score (Figure 3). It is worth noting en passant that planned investments in Qatar, Kuwait, Libya and, to a larger extent, Iraq appear far below potential. On the contrary they seem to be above potential in Algeria, Egypt, Oman and other minor petroleum‐producing countries.

1 For a thorough analysis of the impact of the crisis on energy investment in the Arab world see our Economic Commentary Vol 5 No 1‐2, Jan‐Feb 2010.



Figure 3: Energy Investment Ranking

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Algeria

Kuwait

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Oman

Libya

Iraq

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Tunisia

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Mauritania

Absolute ranking (potential investment)

Pre‐crisis investment ranking

Post‐crisis investment ranking

Resulting perceptual maps

13. The resulting 3‐D perceptual map, which has been flattened to two dimensions for clarity, plots all 15 Arab petroleum‐producing countries. Each plot is equidistant from the country’s three scores of selected attributes, namely country risk, enabling environment and potential investment. The map shows an Ideal Point, which is the centre of gravity of the highest achievable scores. Countries are plotted to reflect the resulting values of their respective scores. They appear in different quadrants at varying distances from the ideal point. They are isolated or close to each other. In the latter case they are clustered to reflect broadly similar perceived investment climates (Figure 4). Figure 4: Pre‐crisis (LHS) and Post‐crisis (RHS) Perceptual Maps

Vast investment potential


Highcountry risk

Lowcountry risk



KSA

UAEKUW

BAH

IRQ

MAUSUD

ALG

TUN

EGYLIB

SYR

YEM

OMA

IDEAL POINT

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Highcountry risk

Lowcountry risk



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UAE KUW

BAH

IRQ

MAU

SUD

ALG

TUN

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14. The pre‐ and post‐crisis perceptual map indicates several mutations:

One country, Saudi Arabia, continues to occupy a unique position in the most appealing quadrant. In addition to its huge petroleum investment potential, Saudi Arabia is increasingly viewed as being a prime investment destination. It has moved nearer to the Ideal Point as a result of a better macro‐economic response to the financial crisis and significant strides in supporting the banking sector and encouraging the private sector.

Next is the cluster formed by Qatar, the UAE and Kuwait. Their investment potential though important is lower than that of Saudi Arabia but they continue to be perceived in the above order as having each a low country risk and a strong enabling environment. However, this cluster, which used to be tightly bound now appears loosely scattered as a result of uneven pace of implementation of policy responses.

Next is the cluster composed of Bahrain, Oman and Tunisia. This group is perceived as having relatively low country risk, a strong enough enabling environment for business, but a low investment potential for lack of sufficient hydrocarbon resources. A further cluster composed of Algeria, Libya and Egypt has a greater investment potential, but is perceived as having a higher, though moderate, country risk and a somewhat weaker enabling environment. This cluster could be extended to include Syria, notwithstanding its low investment potential. Overall the respective positioning of these two clusters has barely been affected.

The last cluster, which is composed of Sudan, Yemen, and Mauritania, is perceived as occupying the least desirable position: modest to low investment potential, much higher country risk, and somewhat a deficient enabling environment. This group has clearly regressed.

Finally, Iraq, which ranks fourth in terms of investment potential, has greatly improved its position compared to previous scorings. However, it still stands in a singular position, very far from the ideal point. Obviously, Iraq needs to improve further the perception of both country risk and the enabling environment for business.

Conclusions

15. Our perceptual mapping has provided a unique pre‐ and post‐financial crisis snapshot of the energy investment climate of the fifteen Arab petroleum‐producing countries. The changes captured in this way range from Saudi Arabia getting nearer to the “ideal point” benchmark, to a significant deterioration of the positioning of Sudan, Mauritania and Yemen. In between, the remaining countries are in three groups in contrasting situations: a) while maintaining their strong positions, Qatar, the UAE and Kuwait have moved apart from each other with Qatar widening its lead; b) both the clusters formed of Oman, Bahrain and Tunisia, and that formed of Libya, Algeria and Egypt (to which Syria could be added) are in neither a better nor a worse position; c) Iraq has made a positive transition: though still very far from the ideal point, its location on the map is getting much better.

16. Our approach is, however, not without limitations. First, and as noted in the introduction, no causal relationship could be assumed for the above changes of positions. Indeed, these changes cannot be solely attributed to policy responses, or lack of responses to the crisis. Conversely, the extent to which a number of issues highlighted by the crisis have affected our perceptual mapping remains imprecise. This is the case of the impact on country risk of generally shallow macro‐economic measures, except for the few countries in the GCC that committed to a stimulus program. Within this region, it is also the case of the impact of the vulnerability of a highly leveraged domestic private sector on the enabling environment for business. A large section of this sector, which is dominated by family‐owned conglomerates with poor governance and transparency record, has failed to address properly the rapid deterioration of its balance sheet. Such examples can also be extended to include the impact of long‐ neglected challenges uncovered by Dubai’s debt troubles. To be sure, the lagging legal infrastructure and enforcement mechanisms, have had an impact on the enabling environment in the UAE. What ultimate impact that is going to have on other GCC countries and beyond remains to be determined.

Economic Commentary

Volume 5 No 4 April 2010


On Being Fa i r , Beaut i fu l and Near ly Per fect : A Ref lect ion On The Eth ics , Economics And Pol i t i c s Of Oi l Pr i ces

The following article by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 12 April 2010. The author wishes to thank the Department of Publications of the Emirates Centre for Strategic Studies and Research (ECSSR) for authorizing the use of material from a forthcoming paper by the author on a similar topic.

1

1. Saudi Arabia’s Minister of Petroleum and Mineral Resources Ali al‐Naimi was recently reported as having described current oil prices as “beautiful.”.

2 This was at the start of the mid‐March OPEC meeting when prices were hovering around $80 per barrel. More recently in Cancun, on the occasion of the meeting of the International Energy Forum (producer‐consumer dialogue), he told the same reporters that prices are “as close to perfect as possible.” Mr Naimi’s statements on the beauty and near perfection of prices surely reflects satisfaction with the market convergence towards the Saudi “fair price.” Readers may remember that in December 2008, at a time when OPEC was in the midst of a crisis management, King 'Abd Allah stated that he wanted the price of oil “to improve and stabilize around $75 per barrel.” He added: “In our view, $75 per barrel would be a fair price.”

3 Since then, prices have remarkably improved indeed and somewhat stabilized: from the low of $40 per barrel when the King made his statement, to around $80 per barrel at the time of writing. While clearly demonstrating leadership and confidence, the King and his oil minister have adopted an ethical policy stance (and aesthetical policy spin) worth exploring.

2. Since the time of Aristotle, policy makers, not only in the Western world (Arab thinkers, through whom much of the Greek philosopher’s work survived, have also been deeply influenced by him), have recognized that ethics (moral philosophy) can provide guidance on issues of public policy. In this commentary we revisit the notion of a fair price for oil and explore the extent to which such a price can be better determined by integrating social ethics with economics and politics. We conclude by offering our views on what fairness should involve for the petroleum exporting countries.

Fair Price: Not so foreign a notion

3. Despite increasing interest in the role played by fairness in economic decisions, discussion on fair prices continues to be shunned by mainstream economists. Last month we were offered a rare opportunity to attend a talk by Martin

1 Ali Aissaoui, “GCC Oil Price Preferences: At the Confluence of Global Energy Security and Local Fiscal Sustainability,” Energy Security in the Gulf: Challenges and Prospects (ECSSR: forthcoming, 2010); proceedings of the ECSSR 15th Annual Energy Conference, Abu Dhabi, November 16–18, 2009. 2 The full quote from the trade press is "Good demand, reliable supply, beautiful prices — we are very happy". 3 King 'Abd Allah’s interview with the Kuwaiti daily newspaper Al‐Seyassah (Politics), dated 29 November 2008.

Feldstein, a Harvard professor of economics, at Robeco’s Middle East Investor conference in Abu Dhabi, where he shared his views on the “new normal” for the US economy. One of the questions put to him was about the implication for US global leadership of the ongoing realignment of economic power and influence in favor of key emerging economies. The follow‐up was in relation to Saudi Arabia’s ability to anchor oil market expectations around a price it considers as fair and how this might challenge US conception of the market. In other places Prof Feldstein might have indulged in oil politics, but not this time. 4 While briefly acknowledging the regained market power of OPEC and the stabilizing role of its leading member, he instead focused on “fair price”, a notion he distanced himself from. What matters to economists, he seemed to suggest, is not whether or not a price is fair but whether it is efficient. According to standard economics textbooks, to be efficient a price must clear the market, i.e. balance supply and demand, and provide the correct signal for investment and divestment.

4. Not all economists avoid this “non‐economic” notion. In the highly‐acclaimed Animal Spirits, Akerlof and Shiller draw on behavioral economics (and the neglected insights of Keynes’ General Theory, from which their book’s title is borrowed) to devote a full chapter to the importance, experiments and theories of fairness.

5 The authors note that current economics has an ambiguous view of fairness since “while on the one hand there is a considerable literature on what is fair or unfair, there is also a tradition that such considerations should take second place in the explanation of economic events.” For them fairness is about bringing into economics ethical arguments based on the theory of equity and more generally on sociologists’ norms. Their remark that “considerations of fairness are a major motivator in many economic decisions”, including in relation to prices, suggests that decision makers may be influenced in ways that deviate from the methods and assumptions of conventional economic theory.

A price dysfunctional markets cannot reveal

5. To be … fair to conventional economists, one should recognize their efforts to move away from the ideals of efficient markets and rational expectations. Despite such efforts, however, they could hardly come to grip with market imperfections. In the case of oil markets, these

4 Political arguments should be expected to be adapted to the audience. See for instance: Henry A. Kissinger and Martin Feldstein, “The Power of Oil Consumers”, The Washington Post, September 18, 2008, Washingtonpost.com [http://www.washingtonpost.com/wp‐dyn/content/article/2008/09/17/AR2008091702969.html]. 5 George A. Akerlof and Robert J. Shiller, Animal Spirits: How Human Psychology Drives the Economy and Why It Matters for Global Capitalism, Princeton and Oxford, Princeton University Press, 2009.

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imperfections are overwhelming. This comes as no surprise given the strategic nature of the natural resource, the complex instruments used for its extraction and trading as a commodity, and the behaviors and motivations of the main market participants. They include the impact of fiscal regimes in the host countries, OPEC output policies, strategic and commercial stockpiling, refining concentration, end‐user taxation, social and environmental externalities, the demands for hedging and speculation in the futures markets, and the speed of information processing and communication.

6. In such conditions the market can clear at any price, most likely between the marginal cost of production and the price of a substitute product; and prices today may differ from prices tomorrow. Figure 1 illustrates the erratic behavior of the oil market in recent years. It shows the evolution of two series of price indices of US West Texas Intermediate (WTI) – the world’s largest oil futures market at the New York Mercantile Exchange (Nymex). The first is the futures price for nearby deliveries and the second is the spread between the first and fourth‐month contracts, approximated as the basis of futures (for the sake of statistical consistency, the one‐month contract is taken as a proxy for the spot price) . The change in the pattern of the two indices is evident. For the first, it is not so much about the normal inter‐day volatility of prices, but rather their sharp swings. For the second, it is not so much about the normal alternation of backwardation (positive basis) and contango (negative basis) as much as their depth. Obviously, several explanations of the factors responsible for such atypical changes have been offered. They include the evolution of demand and supply and how such parameters as price‐inelasticity, macro‐ economic variables, geopolitical uncertainties and producers’ policies have interfered. These explanations have been extended to include the significant increase in trading activities in the futures markets and the effects of excessive speculation.

6

Figure 1: WTI Spot Prices and Futures Time Spreads

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Maximum daily $145.18/bbl

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Minimum daily$33.87/bbl

on Dec. 19, 2008

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6 For the working of the current oil price regime, see for instance Bassam Fattouh, “The Origins and Evolution of the Current International Oil Pricing System: A Critical Assessment”, in Robert Mabro (ed.), Oil in the 21st Century: Issues, Challenges, and Opportunities, New York: Oxford University Press, 2006, p. 41‐100 . For a formal reading of the factors responsible for price changes, see James D. Hamilton, “Understanding Crude Oil Prices”, Mimeo, San Diego: California: University of California, December 2008 .

7. While generally persuasive, these a posteriori explanations are not completely convincing. A simple visual inspection of Figure 1 is sufficient to suggest that recent years’ swings in prompt prices have been too sharp to be just the result of a shift in supply and demand and that the futures spreads have been too wide to be just a reflection of a shift in the economics of oil storage. This leads us to believe that oil markets have been dysfunctional in the sense that they failed to be anchored by fundamentals. And indeed, a dysfunctional market can hardly reveal a fair price.

The confluence of ethics, economics and politics

8. If a fair price cannot be revealed by the market, as we understand it, then we must look beyond. Exactly a year ago (April 2009), we wrote an article in which we attempted to demonstrate that oil prices are likely to be formed at the confluence of technology, economics and politics. 7 In assuming that technology is an implicit factor in economics, such a triadic framework can be reconstituted by substituting ethics (Figure 2). As with our previous assessment process, the level of oil price that would be considered fair rests on three interrelated elements that directly impact the price of oil: economics, politics and ethics.

Figure 2: The confluence of ethics, economics and politics

Politics(emphasis on

fiscal sustainability)

Economics(emphasis on

projects’ viability)

Ethics(emphasis onfairness)

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9. Economics is the relatively easy part of this discussion. It is concerned with the viability of upstream projects under anticipated geological, technological, environmental and market risk conditions. For any given project, the focus in on the expected return needed to justify the investment. This should factor in the costs of exploration, development and production, as well as the cost of capital and a risk premium. In this case, the key determinant of price is the ex‐ante economic cost of a barrel of oil produced from the project.

10. The political element refers to the sovereign political arena of governments and includes agenda setting, decision making and implementation with regard to legislation, regulation and fiscal matters. The political arena may be extended to institutions such as OPEC. The focus is on producing countries’ fiscal policies. In this case, the key determinant of price is the fiscal value of petroleum

7 Ali Aissaoui, “What is a Fair Price for Oil and What Makes $75 a

Barrel Seem Fair?”, Op‐Ed, MEES dated 6 April 2009.

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resources, which can easily be estimated with adequate analytical tools.

11. In contrast, the third and last element is rather elusive. As a sub‐field of applied ethics, social ethics is concerned with the moral obligations of institutions. It differs from normative ethics (what individuals think or believe should be right or wrong), and meta‐ethics (the nature and meaning of moral propositions and judgments). Unfortunately this element, which is expected to provide a concrete basis for presuming fairness, challenges the efficacy of our framework. Whatever its philosophical, sociological and religious underpinning, it can hardly meet precise specifications and measurements.

12. Our framework suffers further limitations. Since we first came up with a price band of $60‐80 per barrel in 2007,

8 we have enhanced and greatly improved its constituent elements. The whole approach, however, remains biased towards oil producers, both companies concerned with projects’ viability and governments anxious about fiscal sustainability. A more comprehensive framework would necessarily entail much different perceptions of fairness and, therefore, would hardly produce a suitable solution.

Finding a sweet spot

13. At the heart of the matter is the duality between petroleum exporting counties and energy importing countries. This can be described by the extreme differences in the structures of trade, gross domestic product (GDP) and governments’ budget receipts. In the IEA countries, for instance, energy imports represented about 21% of total imports in most recent statistics, and energy trade (both imports and exports) represented some 7% of aggregate GDP. By stark contrast, in OPEC countries petroleum exports, i.e. crude oil, oil products, natural gas and natural gas liquids (NGLs), represented about 85% of total exports and petroleum trade represented some 44% of aggregate GDP. Similarly, despite the fact that the IEA countries get more revenues per barrel from taxing final petroleum consumption than OPEC countries get from taxing primary production, the share of these respective revenues in total budget resources was 7% for the IEA and 72% for OPEC.

14. As a result petroleum exporting countries, which exhibit a more consistent macroeconomic pattern, are far more vulnerable to lower oil prices than are most energy importing countries to higher oil prices. It is worth noting in this regard that in reviewing the literature on the macroeconomic impact of oil prices in the consuming countries, some Oxford academics have recently reinterpreted the resulting analyses to question its magnitude and explain today’s minimal impact of relatively higher oil prices. In support of their arguments, they observed that up to mid‐2008 there had been “a steady rise in the price of oil to historically high levels with no

8 Ali Aissaoui, “OPEC: Today’s Market Dilemma and Tomorrow’s

Investment Challenge”, Presentation on the occasion of the 3rd OPEC

Summit, Riyadh, November 2007; and subsequent papers (Ibid.).

observable negative impact on macroeconomic indicators.” 9 The global downturn was, instead, caused by global current account imbalances rather than oil prices. According to the conventional empirical analyses these authors have challenged, oil prices are key determinants of the macroeconomic cycle, and sustained high oil prices significantly affect external accounts, growth, inflation and, ultimately, employment. It is not denied, however, that energy importing developing countries generally suffer the distributional effects of oil prices, and that they have limited fiscal capacity to moderate such effects.

15. Despite these large differences in country vulnerabilities, however, current prices (around $80 per barrel at the time of writing) seem acceptable to all. “It’s a sweet spot,” said Kenneth S Rogoff, a Harvard professor of economics and public policy. “It’s not too low that it’s crushing demand for renewable energy sources or causing debt and fiscal crises in oil‐exporting countries. And it’s not so high that it’s driving African countries deeper into poverty and threatening the recovery in the US and Europe.”

10 But it would be giving too much credit to Prof Rogoff to infer that “sweet spot” can be taken as a metaphor for “fair price.”

Conclusions

16. The permeation of ethics into the discourse about oil prices may be interpreted as a symptom of failure of both markets and policy making based on conventional economics. In the context of efforts by behavioral economists to provide a solid intellectual foundation to ethical principles, the characterization of oil prices in terms of fairness may be interpreted as indicating genuine concern for their detrimental economic effects on both petroleum exporting counties and energy importing countries.

17. Fairness, however, is not about wealth redistribution. From the perspective of the petroleum producing countries, what matters to the sovereign is the petroleum rent, i.e. the portion of revenues, above factor costs and normal return, that should be captured through an appropriate fiscal regime. In this case, a fair price for oil should lie at the confluence of companies’ project viability and governments’ fiscal sustainability. As long as they have enough market power, the producing countries will try and influence the market to meet these expectations. Fairness would further dictate that no policy measure is taken without due regard to its impact on the most economically vulnerable energy‐importing countries.

9 Paul Segal, “Why Do Oil Price Shocks No Longer Shock?” Oxford

Institute for Energy Studies, Working Paper 35, October 2007 , p. 2. Segal’s argument was updated in a Financial Times comment piece: “Searching in Vain for the Oil Shock Effect,” FT.com, September 1, 2009 (http:/ per barrellogs.ft.com/energy‐source/2009/09/01/comment‐searching‐in‐vain‐for‐the‐oil‐shock‐effect/). 10 Quoted by Clifford Kraus in “Oil Prices Find a Sweet Spot for World

Economy”, The New York Times, NYTimes.com, March 31, 2010 (http://www.nytimes.com/2010/03/31 per barrelusiness/energy‐environment/31oil.html).

Economic Commentary

Vol 5 No 5, May 2010 - A Special Report for a Premier Event 1


The Arab Energy Investment Outlook in a Changing Landscape A Summary of APICORP Report to the 9th Arab Energy Conference (Doha, 9‐12 May 2010)

APICORP’s report to the 9th Arab Energy Conference (Doha, 9‐12 May 2010) examines the current state of both the credit market and the oil market and their effect on the Arab energy investment outlook.1 The report is in three parts: the first outlines the dimensions of the twin crises; the second assesses their macroeconomic impact; the third delves more deeply into their effects on the energy investment outlook. This Commentary condenses the report’s findings and highlights the main challenges ahead. It further outlines key policy recommendations.

More than two years after the onset of the credit crisis in the summer of 2007, financial markets have remained stressed, investments sluggish and the outlook for the global economy weak. As long as the oil market was uptrend, up to mid‐2008, the Arab world was thought to be spared from the turmoil. However, the subsequent steep fall in oil prices and the tightening of credits have combined to take a toll on the region’s macroeconomic and energy investment outlook.

To cope with these far‐reaching crises, Arab energy policy makers and project sponsors have had little option but to reassess their investment strategies and scale down projects portfolios. As a result, the uptrend momentum achieved in recent years has been broken. Our current review for the five‐ year period 2010–14 has revealed a lower potential capital investment, which stems largely from the postulation of subdued project costs. The review has also confirmed a further drop in actual capital requirements as a consequence of the continuing shelving and postponement of projects that are no longer viable and fundable. Furthermore, although the combined capital structure of the remaining projects has slightly shifted to equity, the downstream industry remains highly leveraged. In this context, and with due regard to higher risk aversion and tightening credit conditions, securing the appropriate amount and mix of debt is likely to be considerably more challenging than any time before.

Although the credit and oil markets have somewhat stabilized, the speed at which redundant projects are likely to be brought back is still uncertain. Economic and energy investment recovery, will ultimately depend on the pace of global growth. Meanwhile, banks may not resume significant lending yet.

Accordingly, our main policy recommendations fall within four areas. Firstly, Arab governments should continue making up for shrinking foreign capital inflows to the region by reallocating internally more of the assets invested abroad by their sovereign wealth funds. Secondly, in providing liquidity and enhancing capitalization of pan‐ Arab financing institutions, they should target those contributing to the development of the petroleum and energy industries, which remain a powerful lever for economic and social development. Thirdly, in reviewing their investment strategies, public and private project sponsors should exclude from any “option to wait” power and power/water projects. Finally, in the context of heightened risk aversion, and the resulting pressure on the availability and cost of capital, the best policy response is to continue reducing perceived risks. In this regard, our perceptual mapping highlights the importance of improving the investment climate, which should remain the prime concern of policy‐makers.

) ابيكورب(يبحث التقرير المقدم من الشركة العربية لالستثمارات البترولية الراھنة الظروف ) 2010مايو 12-9الدوحة، (العربي التاسع لمؤتمر الطاقة

االستثمارات في قطاع ألسواق االئتمان والنفط العالمية، وتأثيرھما على لى ثالثة أقسام، يستعرض األول ينقسم ھذا التقرير إ. الطاقة بالوطن العربي

األبعاد المختلفة ألزمتي االئتمان والنفط، ثم يقدم الثاني تقييم آلثار األزمتين الثالث فيتناول بمزيد من التعمق على االقتصاد العالمي واإلقليمي، أما القسم

أثر األزمتين على االستثمارات المتوقعة في قطاع الطاقة بالمنطقة العربية وقد أعد ھذا الموجز لتقديم عرض مختصر لالستنتاجات . ة القادمةللفتر

إضافة لذلك يتضمن . وإللقاء الضوء على التحديات الرئيسية للفترة القادمة . الموجز الخطوط العريضة ألھم التوصيات

صيفلقد مضى أكثر من سنتين منذ نشوب األزمة االئتمانية في ، والزالت األسواق المالية متأثرة بذلك مع االستثمارات في تراجع 2007

نتيجة لصعود أسعار . مستمر، بينما يتوقع استمرار ضعف االقتصاد العالميساد االعتقاد في ذلك الوقت بأن المنطقة 2008النفط حتى منتصف عام

التي العربية غير معرضة لعواقب ھذه األزمة، إال أن االنخفاض الحاد تعرضت له أسعار النفط بعد ذلك إضافة إلى استمرار القيود على اإلقراض المصرفي أثرت سلبا على التطلعات االقتصادية واالستثمارية في مجال الطاقة

.بالمنطقةوللتكيف مع تلك األزمة لم يكن أمام المسئولين عن سياسيات الطاقة

ت خيار سوى إعادة تقييم ومروجي ومستثمري المشروعا بالدول العربية استراتيجياتھم االستثمارية وتقليص حجم محافظ المشروعات، وبذلك انعكس

يبين التقرير . اتجاه المسار التصاعدي الذي تحقق خالل السنوات السابقةالمحتملة لفترة الخمس سنوات المقبلة االستثمارات الرأسمالية تراجع حجم

. النخفاض المرتقب في كلفة المشروعات، ومن أھم أسباب ذلك ا14- 2010كما أكد التقرير استمرار انخفاض الحاجة الفعلية لرؤوس األموال نظرا

. لتأجيل وإلغاء المشروعات التي أصبحت غير مجدية أو تمويلھا غير متاحإضافة إلى ذلك، فإن ھيكلة تمويل المشروعات المتبقية قد اتجھت، في

ن التمويل الذاتي، في حين بقيت نسبة االستدانة مجملھا، نحو نسبة أكبر م وإذا أخذنا بعين االعتبار ما سلف . الالحقة مرتفعة لمشروعات الصناعات

باإلضافة إلى ازدياد تجنب المخاطر من قبل البنوك والتشدد الملحوظ في شروط اإلقراض، فإن الحصول على القروض المطلوبة أصبح أكثر تحديا من

.أي وقت مضى رغم بدء عودة االستقرار في األسواق االئتمانية والنفطية، إال أن سرعة ب

غير مؤكدة علما بأن انتعاش . إعادة قيام المشروعات التي أجلت سابقااالقتصاد واالستثمار في قطاع الطاقة سيعتمد في نھاية المطاف على درجة

قراض بالقدر في حين أن البنوك قد ال تستأنف اإل. النمو االقتصادي العالمي .المطلوب

لما تقدم، فإن توصياتنا المقترحة والمتعلقة بالسياسة االستثمارية ووفقاأوال، استمرار الحكومات العربية في : تندرج في أربعة محاور رئيسية

الخارجية للمنطقة بإعادة توظيف تعويض التراجع في تدفق االستثمارات ثانيا، توفير السيولة .لصناديق السيادية خارجيا عن طريق ا أصولھا المستثمرة

وتوجيه وتعزيز رسملة المؤسسات المالية اإلقليمية العاملة في المنطقة العربية ھذه األموال نحو المؤسسات المعنية بتطوير صناعات البترول والطاقة لكونھا

ثالثا، يتوجب على . المنطقة رافعة قوية للنمو االقتصادي واالجتماعي في ول العربية، وھي بصدد مراجعة إستراتيجياتھا االستثمارية، أن تستثني الد

مشروعات قطاعات الطاقة الكھربائية والكھرومائية، العامة منھا أو الخاصة، وأخيرا، في ظل ازدياد تجنب المخاطر، . والتأجيل من خيارات اإلرجاء

على مدى توفر التمويل وارتفاع تكاليفه ، فإن السياسة وتأثير ذلك سلباريطة الخ"وتأكد . المفضلة لمجابھة ذلك ھو العمل على تقليل المخاطر

التي أتستخدمنھا" اإلدراكية ‐وتعرف ب‐ perceptual mapping أھميةباألولوية من قبل صناع السياسات تحسين المناخ االستثماري ليحظى

.االقتصادية لدول المنطقة1 The report and an updated presentation are on www.apicorp‐arabia.com

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Economic Commentary Volume 5 No 6‐7 June‐July 2010


Macondo and Global Oil Supplies and Prices

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated June 28, 2010. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com

1. The massive oil spill at the Macondo well in the US Gulf of Mexico will certainly emerge as the worst and most costly environmental disaster of its kind. At the time of writing, on the ninth week of the spill, preoccupations were still centered on containment, mitigation, and compensation. Larger issues, including the long term social and economic ramifications, BP’s capacity to survive incalculable liabilities, and the broader implications for the petroleum industry, have still to be addressed. Meanwhile, concerns have been voiced about the impact of the incident on oil supplies and prices. In this commentary, we contend that neither the expected loss of supply from deep offshore nor a likely higher production cost will be of sufficient magnitude to affect near term oil prices beyond current market volatility. As a background, we start with a brief overview of the circumstances of the incident and the early policy responses.

Circumstances and Early Policy Responses

2. On 20 April the Deepwater Horizon, a semisubmersible drilling rig owned and manned by Transocean, caught fire and sank. The rig was leased by BP to drill the Macondo prospect located on Mississippi Canyon Block 252 in the Gulf of Mexico some 65km off the Louisiana coast (Figure 1). The incident has assumedly been caused by a surge in pressure that the wellhead blowout preventer failed to contain. It killed 11 members of a drilling crew of 126, injured many, and triggered a massive oil spill.

Figure 1: The Macondo Spill – Projected Trajectory For 21 June

Source: US National Oceanic and Atmospheric Association (NOAA)

3. BP, in its capacity as the majority partner and operator of the prospect, has accepted responsibility for the spill. To cap or limit the flow of oil, the company has embarked on a series of tentative, remotely‐piloted operations on the ocean floor, some 1,500m below sea level. An increasing part, but not all of the flow, has been captured. At the same time and as an ultimate solution to overcome the flow, Transocean was allowed to drill two relief

wells to be completed by August. Either or both wells will be used to ease pressure from the leaking well and inject enough cement to plug it definitely. Meanwhile, BP has pledged itself to make available whatever resources required for the clean‐up, recovery and remediation. It has further come under political pressure to put $20bn in an escrow fund to cover anticipated claims.

4. The Macondo spill is the sort of incident that is likely to usher in a radical overhaul of US energy policy. A major component of a pending energy and climate bill has already been put on hold. The public and political outrage provoked by the spill has forced President Barack Obama into a U‐turn on his plan to expand domestic offshore exploration. The resulting six‐month extension of a moratorium on drilling new deepwater wells in the Outer Continental Shelf is likely to affect production further in the future. To what extent depends on the ultimate length of the moratorium.

Likely Impact on US Oil and Gas

5. As outlined in Box 1, US offshore petroleum, the bulk of which in the Gulf of Mexico, is an important source of US oil and gas supply and a key domestic option to reduce “dependence of foreign oil” and ensure the transition towards embracing “a clean energy future”. However, the Macondo spill has cast doubts on the option. In addition, for reasons discussed further below, the ripple effects could reach onshore shale gas as well.

6. Further to the suspension of permits to drill new deepwater wells for six months, the pending lease sale in the Gulf of Mexico and the proposed lease sale off the coast of Virginia in the Atlantic have both been canceled. In addition, more than 30 deepwater exploration wells being drilled in the Gulf of Mexico have been halted. Obviously, Alaska is no exception, since all planned exploration off the northern state’s coast have been suspended. Besides, directives have been issued to all lessees and operators on the Outer Continental Shelf to implement stronger safety requirements. Meanwhile, the authorities in charge continue examining and testing deepwater production facilities as part of increased enforcement of existing safety regulations.

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Box 1: U.S. Offshore Petroleum in a Nutshell

B1. The US offshore, both state and federal, has an estimated 4.7bn barrels of proven reserves of petroleum (crude oil, condensate and NGLs), 89% of which in the Gulf of Mexico. These reserves represent 17% of the US total. In 2009 offshore petroleum production reached 1.7mn b/d, accounting for 19% of total domestic production of liquid fuels (including biofuels), 18% of net imports of petroleum and 9% of total liquid fuel consumption.

B2. Prior to Macondo, the offshore sector was seen as a major contributor to the revival of US petroleum production. In the short term, the largest sources of the increase were expected from deepwater fields that started producing in 2009 or expected to start soon, mostly in the Gulf of Mexico. With augmented production from fields that came on stream earlier, they could maintain growth up to 2015. The lifting of the moratorium on drilling in the Outer Continental Shelf (Gulf of Mexico, Atlantic, and Pacific) was expected to help sustain offshore production beyond 2015.

Sources: Compiled from US EIA, BP and Anadarko data.

Economic Commentary Volume 5 No 6‐7 June‐July 2010


7. To be sure, oil companies will face difficulties in expanding oil and gas production both offshore and onshore. US offshore has so far been seen as ideal for exploration and development, thanks to a conducive legal, regulatory and fiscal framework. Henceforth, stricter regulations, tighter safety standards and higher royalties or fees (to fill up the Oil Spill Liability Trust Fund) could drive companies to shale gas, onshore. However, shale gas has also come under renewed scrutiny following recent cases of blowouts and groundwater contamination. More stringent rules are likely to require drillers to disclose properly the potential hazards of hydraulic fracturing, which requires breaking up rock with a mixture of water, sand and chemicals to free the gas. Several local and international oil and gas companies, which have recently acquired stakes in shale gas, or expanded existing ones, have expressed concerns about the potential impact of pending tougher rules and regulations.

8. Back to offshore, it is hard to put a figure on the impact of Macondo on oil output. Industry sources indicate that in the short term production from existing fields is likely to slow down, leading to a loss of some 100,000 b/d. In the medium term, up to 2015, this amount could triple as fields planned to come on stream are postponed until the current review of government oversight and industry safety procedures is concluded. The outlook beyond 2015 depends on the duration of the moratorium. As long as the exact circumstances of the incident that caused the spill are not clarified, and the oil industry is not prepared to deal with similar events, the moratorium will remain in force. Obviously, politicians could decide otherwise should they deem it to be in US economic and strategic interests.

Likely Impact on World’s Supply, Costs and Prices

9. World offshore oil production is currently estimated at 25mn b/d, about 29% of global supply. Driven by fast developing deepwater (Figure 2), it should account for 45% of global supply growth up to 2015, against 24% during the 2000‐08 period (Table 1). No matter what share of US production is lost, it would hardly affect this outlook, unless output from key offshore provinces in Brazil, Angola, and Nigeria were equally disrupted. Although Brazil has more room for maneuver, it may face a dilemma in valuing the option to wait. It may turn its review of BP’s recent acquisition of deepwater assets to good account and learn more about whether the Macondo incident resulted from specific area methods or from common industry practice. It may also decide to extend Petrobras’s operating control and move forward to benefit from a relocation of deepwater rigs. In any event, neither Brazil nor, a fortiori, the other countries can do for long without deep offshore oil.

Figure 2: Key Trends In Worldwide Offshore Oil Production

0

5

10

15

20

25

30

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Million barrels per day

Deep waters Shallow waters

Sources: IEA (total offshore) and Douglas Westwood (deep water)Sources: IEA (total offshore) and Douglas Westwood (deep water)

Table 1: Outlook for World Oil Supply (million b/d)

2000 2008 2015 2030

Crude oil 66.0 70.6 69.2 76.7

Non‐OPEC 38.2 39.4 36.6 35.3

Of which offshore 15.9 15.3 15.4 16.3

OPEC 27.8 31.2 32.6 41.4

Of which offshore 6.7 9.2 10.8 7.4

NGLS 7.8 10.7 13.9 18.9

Non‐OPEC 5.0 5.8 6.6 7.6

OPEC 2.8 4.9 7.3 11.3

Non‐conventional oil 1.3 1.8 3.5 7.4

Non‐OPEC 1.1 1.7 3.2 6.3

OPEC 0.2 0.1 0.3 1.1

Total production 75.1 83.1 86.6 103.0

Non‐OPEC 44.3 46.9 46.4 49.2

OPEC 30.8 36.2 40.2 53.8

Processing gains 1.7 1.5 1.8 2.2

World oil supply 76.8 84.6 88.4 105.2

Sources: IEA, 2009 WEO (Offshore data from 2008 WEO).

10. This is not denying the likely impact on the cost of production, even if suspension of drilling in the Gulf of Mexico is expected to depress rig prices. Higher costs, either on tighter regulation and oversight or on moving to regions perceived as politically uncertain, would most likely come in the form of rising risk premiums. Our normal working assumption for such a premium is 15% of the total cost of a typical large scale project in a difficult environment. Raising the premium to 20% would increase the economic cost of deep water by $3 to $4 per barrel.

1 No matter what further assumptions are made, projects’ breakeven prices remain within our recently adjusted anchor band of $70‐90 per barrel, which takes in higher costs of marginal production from enhanced oil recovery, heavy oil, bitumen, and oil shales.

2

11. Finally, whatever scenario is chosen for the impact of Macondo on oil supply and costs, one should bear in mind that the global supply‐demand balance implied by Table 1 assumes that demand is first met by non‐OPEC. This puts the burden of balancing the market on OPEC, which cannot assume such a role without an additional capacity to draw from. OPEC currently holds more than 6mn b/d of spare capacity, nearly four times US offshore production. The fact that two‐thirds is in Saudi Arabia underscores its greater responsibility for stabilizing the market. Recent assertions by Saudi policy makers that their country “remained a force for moderation on oil prices” 3 should help keep market expectations firmly anchored around the so‐called fair, established price of $75 per barrel.

Conclusions

12. The Macondo spill has cast a shadow on the development of one of the key sources of growth of petroleum. The incident is very likely to restrict deep offshore production and increase its cost, but not in a proportion that could affect significantly global supplies in the near term. As a result, oil prices are unlikely to move outside our anchor band of $70‐90 per barrel. Any longer term outlook must remain conjectural until we gain a better understanding of what precisely caused the incident and how energy policy makers and the petroleum industry are likely to deal with its aftermath.

1 Using a different, more exhaustive approach, Deutsche Bank reaches a comparable result. See Paul Sankey et al, ‘Macondo and the Global Deepwater’, Deutsche Bank Securities, June 2010, pp32‐36. 2 The framework used to determine such a band has been updated by Ali Aissaoui in ‘On Being Fair, Beautiful And Nearly Perfect: A Reflection On The Ethics, Economics And Politics Of Oil Prices’ (MEES, 12 April). 3 Petroleum Policy Intelligence, ‘Saudi Arabia: Interview With Minister of Petroleum Ali Naimi’, Special Report, 7 and 10 June 2010.

Economic Commentary Volume 5 No 8 August 2010


Finding A Needle In the Dodd‐Frank Haystack And Wondering What To Expect From ItOur Readers Warn Of The Unintended Consequences Of The ‘Disclosure Of Payments By Resource Extraction Issuers’

This commentary has been prepared by Ali Aissaoui, Senior Consultant at APICORP. The author wishes to thank, while absolving from responsibility, the many readers who contributed their remarks and interpretations. For privacy purposes, the names of those quoted have been abbreviated to their initials.

1. On 21 June 2010, the day President Barak Obama was to sign the Dodd‐Frank Act into law, we sent an email to our readers seeking their comments on Section 1504 of the Act, a clause requiring “disclosure of payments by resource extraction issuers”.1 Even though tentative, their preliminary remarks offer interesting insights into a provision which has taken the petroleum industry by complete surprise.

What is it about in a nutshell

2. The Dodd‐Frank Act, also known as the “Wall Street Reform and Consumer Protection Act”, is the legislative response of the Obama administration to the 2007‐2009 financial crisis. It provides for a sweeping overhaul of US financial regulation with the aim of promoting stability, identifying and addressing systemic risks, organizing orderly liquidation of systemically important firms (the “too big to fail”), ending bailouts, ensuring transparency and accountability of Wall‐Street, and protecting investors and consumers from misleading and abusive practices of financial services providers.

3. This wide‐ranging piece of legislation contains specific transparency provisions. In particular, resource extraction companies, registered with the Security and Exchange Commission (SEC), will have to publicly disclose payments made to inter alia a foreign government for the purpose of commercial development of oil, natural gas and minerals. Payments include taxes, royalties, fees (of which license fees), production entitlements, bonuses, and other material benefits (interpreted as tangible monetary rewards).

Unforeseen by the petroleum industry

4. Judging from remarks by well‐informed readers, the petroleum industry was taken by surprise. The first to admit it is PS, a senior energy policy researcher based in London:

2

This remark is echoed from Geneva by GL, an academic in the area of industrial and energy economics:

5. It is unclear how this information lapse occurred. A comment by PH, a lead oil industry analyst with an investment bank in London, suggests a plausible justification:

1 The Dodd‐Frank Act (HR 4173) can be downloaded from the website of the US Government Printing Office [www.gpo.gov]. 2 All quotes have been excerpted from emails sent to the author between 21 and 27 July 2010.

6. Indeed, such additions, if made during ultimate conference negotiations to reconcile both House and Senate versions of the bill, may catch many off‐guard. This is probably what happened to the American Petroleum Institute (API), the industry main advocacy group in Washington. API clearly missed the opportunity to alter the negative perceptions US lawmakers have of the petroleum industry, in the aftermath of the disastrous oil spill in the Gulf of Mexico.3 But the addition to the bill did not go unnoticed by NGOs. In a press release dated 15 July, Earth Rights International (ERI) revealed that a coalition of over 30 human rights, environmental, socially responsible investment, religious, and anti‐corruption and good governance groups advocated for the passage of the provision.

A transparency for anti‐bribery initiative?

7. PH’s reference to the section on Congo (Section 1502 on Conflict Minerals) and NGOs’ interpretations of the provision in question seem to be implicit in some readers’ remarks. MNA, a social entrepreneur from London, argued that:

8. This view is upheld from Bahrain by DHL, a senior executive with an asset management bank advocating responsible investing:

3 Ali Aissaoui, “Macondo And Global Oil Supplies And Prices”, MEES dated 28 June 2010.

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I am amazed that you are the first to raise the issue and no one has commented until now.

Thank you for flagging this – I had not read about [it] on any news article and was not aware of it.

It was clearly added to the bill during the process (quite common in the US for totally unrelated sections to be added to bills as they go through), like the section on conflict minerals from the Congo.

Unless I completely misunderstood what the [clause] refers to: unclear as to what the actual intention […] is and why it was incorporated within the Act, but as a side point, wouldn't it potentially have positive ramifications on fighting corruption in resource‐rich countries […]? Something Paul Colliera has called for I believe but with emphasis on putting pressure on [these countries’] governments to adhere to a set of existing international resource extraction transparency standards.

a Editor’s note: Paul Collier is professor of economics at the University of Oxford and director of the Centre for the Study of African Economies. He focused his research on issues surrounding the 'resource curse', a theme further developed in his latest book: “The Plundered Planet: How to Reconcile Prosperity With Nature”, Allen Lane (hardback) and Penguin, 2010.

The extractive industries convention signed [some] years ago would provide a useful benchmark […]. That is widely regarded as a positive move to protect local communities from corrupt government. If on the other hand this is about US ambitions of extra‐territorial sovereignty then it is clearly less attractive to other nations.

Economic Commentary Volume 5 No 8 August 2010


9. There are many international anti‐corruption and anti‐bribery conventions. But what DHL was probably referring to is the Extractive Industries Transparency Initiative (EITI), which sets a global standard for transparency in oil, gas and mining. Since implemented in 2004, EITI has been hailed, including by US lawmakers, as a model for addressing the challenges created when governments receive a windfall of revenue from their resources but fail to pass it through to their citizens. What is the point then for the US Congress of legislating unilaterally, and for NGOs, such as ERI, of describing the piece of legislation in question as “[setting] new international standards for transparency in the extractive industry”?

10. To be sure most readers, who sent their remarks, were explicit in supporting efforts to improve corporate transparency. Some of them, however, made interesting points of clarification with regards to transparency in revenue payments. This is for instance the case of AS, a senior oil industry analyst with an investment bank in Washington:

11. The preceding arguments are taken further by NAL, the head of a Geneva‐based energy consulting firm:

Unintended consequences

12. NAL also points to unintended effects of the provision that could be detrimental to oil companies registered with SEC:

A corollary of which is elaborated by PS, who conjectures more troubles for US oil companies in particular:

13. And, as further contended by IW, a senior executive with a London‐based international business development company, there may be no limit to the unintended consequences:

While waiting for SEC rule making

14. Other readers have indicated that they had referred the matter to legal advisors for guidance. But expert opinions will be contingent on progress in implementing reform. SEC may well emulate the rules the Department of Justice has been enforcing under the 1977 Foreign Corrupt Practices Act (amended 1998).4 A further hint of what to expect is given by JM, a senior energy policy advisor based in London, who rather perceives a parallel with EITI:

15. Further insight into the shape of things to come and their possible consequences are provided by GL:

Conclusions

16. Readers have proved themselves to be a trustworthy and valuable source of analysis and inspiration. The overall impression from their remarks is that of disappointment with a transparency law that is redundant and unnecessary. It appears that in seeking to hold the legal and ethical high‐ground, US legislators have unwittingly shot themselves in the foot. It is very likely indeed that US oil companies operating overseas will bear the brunt of the regulations put in motion. As for the resource‐rich countries, we believe that persuading, rather than coercing, them to fully adhere to the legitimate international charters, conventions and standards in place can be more conducive to better governance.

4 An overview of this Act is on [www.justice.gov/criminal/fraud/fcpa].

I think the intent of the legislation is to reduce the potential for corruption in oil producing countries by requiring that US companies disclose who they are making payments to. Normal payments to government tax collectors will not cause much alarm, but you could think of this as "transparency for bribes" law.

While transparency is clearly a laudable objective, it is strange that this disclosure requirement was attached to the financial reform bill. This imposed transparency, if enforced by the SEC, will be embarrassing to governments of some oil exporting countries, especially those where corruption diverts much of government revenue to uses other than public welfare. Non‐governmental human rights organizations will in the future pore over annual reports and 10K filings of US‐listed oil companies to collect and compile the sums of their payments to various target governments around the world.

With regard to some host governments, this will be just one more reason to avoid granting E&P [exploration and production] agreements to US‐listed companies.

It seems to me someone has not thought out the implications of this or simply not understood them. A classic example of Washington not having a clue what goes on outside the Beltway. […] If it is passed and enforced, most oil companies falling under its spell i.e. all US companies would almost certainly lose their overseas licenses as it would be a breach of their contractual terms.

Yet another reason why energy companies might decide to relocate and operate outside the US. It is interesting that BP is trying to shift some of its US assets. Given the current mood I would not be surprised if BP pulls out of the US entirely and heads for Libya, Iraq and other countries where there seems to be more realism not driven by the politics of the Hill. b

b Editor’s note: The (Capitol) Hill is a metonym for the US Congress.

I am not a lawyer and there might be some [future SEC rule making] effectively restricting the impact of this norm, but if it is what it appears to be then my expectation would be that all “resource extraction issuers” will seriously consider delisting in the US. Maybe the solution will be publication of some aggregate set of numbers, but if truly analytical data are requested I expect many companies may find it difficult. The irony is that this will encourage governments to get revenue in other, indirect and even less transparent ways – possibilities are as numerous as stars in the sky.

It seems to me that section 1504 essentially makes EITI a part of US requirements for companies which raise money in the US. It seems to require information on a project basis, as well as a country basis. This could be commercially sensitive and perhaps the regulations will not require this project information to be made public.

Economic Commentary Volume 5 No 9 September 2010


Joint Report to the G20 on Energy Subsidies: A Critical Review

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 30 August 2010. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com

1. In response to a request by the G20 leaders, four intergovernmental organizations, namely the IEA, OECD, OPEC and the World Bank, delivered in June 2010 in Toronto a joint report under the title ‘Analysis of the Scope of Energy Subsidies and Suggestions for the G20 Initiative’. The initiative is that agreed in the previous Pittsburgh Summit, which committed to rationalize and phase out over the medium term inefficient fossil fuel subsidies that encourage wasteful consumption. The report, which is available on the website of each of the four institutions that co‐authored it, deserves an audience beyond the confines of experts and policy‐makers involved in the proceedings and deliberations of the G20.

2. As part of our efforts to encourage informed debate on topical energy policy issues involving or affecting petroleum producing countries, we critically review in three parts the joint report. In the first part we consider the likely motivations and expectations regarding the G20 initiative. In the second part we delve into the report’s structure and main findings. In the third part we point out some of its limitations and ambiguities. We finally conclude by highlighting the unviability of the report’s key recommendations and the resulting challenges facing the initiative, or the intended multilateral implementation thereof.

Motivations and Expectations

3. We may start by asking why the issue of fossil fuel subsidies is so timely and urgent as to have been placed high on the G20 agenda in Pittsburgh in September 2009. Current debate in the US about a pending energy and climate change bill may provide a clue. The bill has indeed raised concerns that, if passed, could subject the US economy to higher environmental mitigation costs that could seriously compromise its competitiveness. While certainly attentive to this, President Barack Obama reflected, in closing press conference remarks in Pittsburgh, broader and more far reaching concerns:

1

[…], we agreed to phase out subsidies for fossil fuels so that we can transition to a 21st century energy economy […]. This reform will increase our energy security. It will help transform our economy, so that we're creating the clean energy jobs of the future. And it will help us combat the threat posed by climate change. […] all nations have a responsibility to meet this challenge, and together, we have taken a substantial step forward in meeting that responsibility.

4. These remarks beg the further question of how fossil fuel subsidies have come to be viewed as a multilateral issue. Taxes, subsidies and budget transfers are standard economic policy instruments long used by governments to attain social and economic objectives. Policy reforms in the field, a recurrent theme of the IMF, the World Bank and several regional economic organizations, have been advocated on a country

1 by President Barack Obama at the G20 Closing Press Conference, 25 September 2009, Pittsburgh, US.

basis. Complaints about subsidies, which are most prevalent in energy, agriculture and fisheries, when addressed through the WTO can still be disaggregated into bilateral disputes. However, as climate change issues have gained prominence, growing international pressure to curb greenhouse gas (GHG) emissions has focused attention on the broader impacts of fossil fuels subsidies. Much in the same vein, the issue attracted the interest of NGOs involved in the global politics of sustainable development. The Global Subsidies Initiative (GSI), for instance, started before Pittsburg on an ambitious program to analyze and assess the “corrosive” effects fossil‐fuel subsidies can have on economic development, the environment and governance.2

5. This being noted, the facts remain that the G20 leaders agreed “to phase out and rationalize over the medium term inefficient fossil fuel subsidies while providing targeted support for the poorest”, contending that “inefficient fossil fuel subsidies encourage wasteful consumption, reduce … energy security, impede investment in clean energy sources and undermine efforts to deal with the threat of climate change”.

3 To implement their commitment, they called on the already mentioned institutions to provide an analysis of the scope of energy subsidies and to offer suggestions for their initiative.

Structure and Main Findings

6. The joint report on energy subsidies draws on original in‐house studies and a large body of economic literature (some 150 references and background papers are listed in the report and its annexes). To address the issue in a coherent framework, the analysis has been carried out in four logical steps.

7. First is defining the scope of energy subsidies. Against a backdrop of the role of energy in economic growth, poverty reduction and environmental conservation, the authors candidly admit that, in the context of the G20, finding a commonly agreed definition of subsidies proved most challenging. In deciding to consider all forms of energy subsidies and taxes (negative subsidies), they focused on answering the question: “What makes for inefficient subsidies leading to wasteful consumption?” This, they conclude, “requires understanding the circumstances of each country and the impact of the different subsidies in use.” They suggest, within a broader development context and from a welfare perspective, the social cost‐benefit analysis (SCBA) as the most effective framework for assessing the impact of changes in energy subsidies. Worth noting, however, is that the empirical studies, summarized in the reports’ annexes, are rather based on more practical computable general equilibrium (CGE) models.

8. Second is identifying and quantifying subsidies. After providing a comprehensive taxonomy of energy subsidies, the authors discuss how different types of subsidies can be measured and identify the gaps in existing information, before proposing a framework for organizing the necessary data.

2 GSI is one of the initiatives hosted by the International Institute for Sustainable Development, a Canada‐based non‐governmental research organization in the area of sustainable development. 3 G20 Leaders’ Statement, Pittsburgh, 24‐25 September 2009.

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Estimates of energy subsidies are tentatively given for both consumption and production. Subsidies to alternative fuels are further highlighted. The most extensive analysis is that prepared by the IEA on fossil fuels consumption subsidies. Using a price‐gap methodology, which involves a differential between a benchmark price and the retail price, these subsidies are put at $557bn in 2008 (an exceptional year, indeed). The report, however, notes that the price‐gap methodology, which “is tied to the opportunity cost of a pricing policy”, has serious shortcomings. At the risk of simplifying the authors’ complex arguments about what constitutes a relevant benchmark, we can say that, for the IEA, it is the price quoted in global markets, but for OPEC it is the cost of production.

9. Third is reforming and phasing out inefficient energy subsidies. The authors demonstrate that poorly implemented energy subsidies are costly to the economy and detrimental to the environment. Using modeling‐based analyses they expect the removal of inefficient subsidies to have significant positive effects. However, the authors also raise equity issues. Drawing on several studies reviewed by the Independent Evaluation Group of the World Bank, they provide further evidence that universal or general price subsidies tend to benefit high income groups more than the poor. Furthermore they caution, on the basis of case studies included in the annexes, that phasing out subsidies for kerosene, LPG and electricity, which are vital to developing communities, would worsen poverty and cause more damage to the environment. Finally, taking a broader and longer run perspective, the authors rely on recent OECD‐IEA studies to validate the impact on global GHG emissions. A central scenario suggests that removing fossil fuel subsidies would lead to an emission reduction of 8% in 2050, compared to a business as usual baseline. This rate increases to 10% when subsidy removal is combined with emission caps in non‐subsidy reform countries that committed to emission targets.

Figure 1: Phasing Out Energy Subsidies: A Decision Tree Prepared by the World Bank

Efficiency test of the subsidy tool through Cost Benefit AnalysisAre energy subsidies efficient in reaching their intended objectives?

If yes, is their net benefit positive?

Wasteful test of the subsidy toolDo energy subsidies avoid wasteful consumption?

Cost effectiveness analysis of alternative policy toolsAre energy subsidies the most cost effective policy tools to achieve

the intended objectives?

Cost effectiveness of public fundsAre the underlying objectives of energy subsidies a priority with

respect to other policy objectives?

Phase 1

Phase 2

Phase 3

Phase 4

If no, phase out

If no, phase out

If no, phase out

If no, phase out

Yes, with limited Impact on consumption

If yes, proceed

Yes, but with major impact on consumption

If yes, keep the selected subsidies in an exception list and keep monitoring over time to ensure the fulfillment of all tests above

If yes, proceed

Source: IEA, OECD, OPEC, World Bank Joint Report on Energy Subsidies

10. Fourth is suggesting implementation. Drawing on case studies in both developed and developing countries, the authors provide a roadmap to policy makers. As shown in the decision tree of Figure 1, a necessary first step in implementing reforms is identifying those subsidies that are inefficient and lead to wasteful consumption. The authors further examine the implementation challenges stemming from the political

economy and social constraints. This brings them to suggest relevant policy tools to address distributional issues and to protect the poor. In this context, they conclude by highlighting the benefits of targeting subsidies.

Limitations and Ambiguities

11. The depth with which the issue of energy subsidies has been attended in the joint report leaves little room for criticism. However, three remarks can be outlined. The first is about exhaustiveness. Despite their declared attempt to explore all forms of taxes and subsidies, the authors have overlooked the so‐called tax‐inclusive subsidy. This form of subsidy, which exposes a Ramsey‐like suboptimal taxation, has been highlighted in a recent IMF Staff Position Note duly referenced in the report. 4

12. The second remark is that despite a consensual approach, which involved “much debate and hard work”, the authors could not conceal significant differences in defining and measuring inefficient energy subsidies and, if these were to be phased out, in the way that could be done. Most of these differences, which stem naturally from the authors’ differing perspectives, can be easily discerned in numerous exceptions, caveats and qualifications. But a few are less apparent and could only be inferred from the repetitive assertions of what should be obvious, but gradually not, such as “should subsidy phase‐out be justified on the grounds of climate change mitigation objectives, then the provisions of the United Nations Framework Convention on Climate Change should apply.”

13. The third remark is that the authors failed to draw attention to the unfeasibility of one of their key recommendations, which maintains that “taking account the sovereign rights of countries to develop economic and social policies, subsidies are fundamentally country‐specific, and should be based on national circumstances.” In denoting an absence of common definition, shared target and specific implementation schedule, the country‐specific approach can hardly be seen as viable.

Conclusions

14. The IEA, OECD, OPEC and World Bank joint report to the G20 provides an insightful analysis and practical suggestions for tackling energy subsidies. Based on seasoned professional expertise, the findings and recommendations have been presented in a clear, coherent and logical sequence of steps focused on defining, measuring, reforming and implementing. Yet, key recommendations are bound to be divisive and some of them, such as the “country‐specific” approach, may carry the seeds of their own failure.

15. Not unexpectedly, evidence from information that leaked out of the G20 in Toronto suggests that finance and energy ministers have to overcome major hurdles in delivering on their implied commitment to develop “implementation strategies and timeframes.” How much progress can they make ahead of the Seoul summit depends on how their governments resolve the dilemma posed to them: integrating a multilaterally agreed initiative on energy subsidies into their public policy making without undermining the legitimacy of their political economy.

4 David Coady et al, “Petroleum Product Subsidies: Costly, Inequitable and Rising”, IMF Staff Position Note dated 25 February 2010.

Economic Commentary Volume 5 No 10‐11 October‐November 2010

© Arab Petroleum Investments Corporation 2006 Page 25/31 Comments or feedback to research@apicorp‐arabia.com

MENA Energy Investment Outlook: Recovery Despite Uncertainty

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 4 October 2010. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com.

1. In the present commentary we shall provide insight into the key trends and challenges facing energy investments in the Middle East and North Africa (MENA) for the five‐year period 2011‐15. The context of the review is that of a global demand for energy gradually recovering and of crude oil prices stabilizing within an adjusted anchor price range of $70‐90/bbl. This has encouraged investors to bring back in line some of the oil‐based projects they had previously shelved or postponed and to slate for development new ones. In the gas sector, however, export projects face a more challenging market in the wake of the US shale gas revolution. As world gas prices have come under tremendous pressure, the option to wait may have more value for project sponsors. Our assumption is that gas prices, which are greatly deviating from oil price‐parity, will keep diverging between regional markets: $4‐5/MBtu in fully liberalized, well supplied markets, to $8‐10/MBtu in markets where oil‐linked prices prevail.

2. Against this setting the rest of the commentary is in three main parts. Part 1 describes the review methodology. Part 2 presents an overview of key trends, highlighting investment prospects in the power generation sector, which has emerged as a key driver of growth. Part 3 extends the analysis to the challenges faced by investors and project sponsors.

Our Methodological Framework

3. Except for the growth‐based power and power/water generation (see Box ‘Investment In The Power generation Sector’), our review of investments relies on a project based approach. This is underpinned by a database of planned (and announced) public and private projects along the energy supply chain. The review, which identifies the main steps in project life cycle, takes in projects that have apparently secured a final investment decision (FID). The time frame is a rolling five‐year period, which coincides with the planning frame of most of the project sponsors involved. Energy infrastructure projects are grouped in two supply chains (oil and gas) and, for each chain, along three links (upstream, midstream and downstream). The downstream is extended to include petrochemicals, which are either oil or gas based.

4. It should be noted that since the onset of the global financial crisis in the summer of 2007 this framework has been amended in an attempt to reflect the greater uncertainties surrounding the outlook. As a result, our findings have been summarized into two categories:

First, the potential capital investment, which takes in all projects that originally secured a FID, is updated in response to changes in project costs.

Second, actual capital investment requirements are deducted from the above by taking out the apparently shelved or postponed projects, beyond the review period.

5 The systematic repetition of the review year after year, since 2003, has made trends easier to identify. Furthermore a key attribute of this framework is that energy demand and prices are

implicit determinants. In contrast, project costs, feedstock and funding are explicit. This allows the analysis to be extended to the challenges posed by the explicit factors.

Overview of Key Trends

6. Figure 1 shows that growth in MENA energy capital investments is expected to recover from the post‐crisis contraction. Indeed, current review for the period 2011‐15 points to a higher potential investment of $615 billion, compared to $550 billion in the last review. Furthermore, the total amount of investments shelved or postponed has dropped to 22% of potential, compared to 30% in the last review. As a result, actual capital requirements should amount to $478 billion for the period 2011‐15, compared to $385 billion in the last review.

Figure 1: Rolling 5‐year reviews of MENA energy investments

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2005-09 Review

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Geographical Pattern 7. Closely reflecting the distribution pattern of crude oil and natural gas reserves in the region, two‐thirds of the energy capital investment potential continues to be located in five countries namely Saudi Arabia, Iran, the UAE, Qatar and Algeria. In the present review the UAE has taken over Qatar as the third biggest potential energy investor in the region (Figure 2). Furthermore, in terms of actual capital requirements, the UAE ranks second to Saudi Arabia, while Iran is relegated to the fourth place.

Figure 2: Geographical pattern of energy investment

0 30 60 90 120 150

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Jordan

Bahrain

Tunisia

Sudan

Syria

Oman

Libya

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8. In Saudi Arabia, potential capital investment is estimated at $130 billion. With Saudi Aramco and SABIC reaffirming their commitment to implement their investment programs, shelved or postponed projects are expected to decline to 6% of potential,

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compared to 21% in the previous review. In the UAE, revised potential investment totals $74 billion with projects made redundant amounting to 20%. Iran’s potential investments amount to some $85 billion. In this country, poor investment climate has been aggravated by tighter international sanctions targeting the energy sector. As a result, the ratio of shelved or postponed projects has increased to 45% of potential. Potential capital investment in Qatar is estimated at $70 billion. In this country, we continue to assume that the moratorium on further development of the North Field gas reserves (beyond the Pearl and Barzan projects) will not be lifted during the review period. Accordingly, shelved and postponed projects, even though much less than the 36% found in the last review, remain relatively high at 32% of potential. In Algeria, Sonatrach is anticipated to recover quickly from its recent paralysis and resume normal investment activities. Hence, potential investment has been revised upward to $57 billion, while postponed projects are expected to drop to 19% of potential, compared to 31% in the last review.

9. Although similar trends are evident in the rest of the key petroleum producing countries, the below‐potential Kuwait and Iraq deserve some explanation. Kuwait has the highest rate of postponed and shelved projects after Iran of some 43%. This, however, has more to do with the dynamics of domestic politics and policy than the effect of global uncertainties or international circumstances. In this context, it is difficult to estimate the country’s actual capital requirements as long as major components of the upstream program remain at a standstill, or key downstream projects such as the al‐Zour refinery are undecided. Iraq, where the ambitions to achieve the full development of the oil sector have been revived, the extent of foreign investors’ contribution will depend on the ability of the Iraqi authorities to provide an ultimate solution to recurrent security problems.

Sectoral Pattern 10. Of the $478 billion of actual capital requirements in MENA region, the oil supply chain accounts for 41%. This will be needed to develop new production and transportation capacity, sustain current production through enhanced oil recovery (EOR) programs, and finalize the expansion program of the refining and oil‐based refining/petrochemical sectors. The gas supply chain accounts for 35%. This amount will be needed to develop new production and transportation capacity for both natural gas and the associated NGLs, expand capacity to meet domestic requirements and finalize ongoing export based projects, including gas based petrochemicals and fertilizers.

11. Capital requirements in the oil, gas and nuclear fuelled power generation sector represent the remaining 24% (capital expenditures for nuclear based power generation is implicit in the UAE’s case). 1 As already noted in the methodology section, investment in this sector is growth‐based. Therefore, no assumption of shelved or postponed projects is made. The resulting prospect of this chronically under‐developed sector is highlighted in the Box. Contraction of MENA economies, and the apparently lesser demand for electricity, may provide temporary respite to a constrained capacity. Yet, this sector needs to catch up with an unmet potential demand.

1 While Iran’s first nuclear power plant, the Bushehr 1 reactor, was inaugurated in August 2010 (to come on stream soon after), Abu Dhabi’s first such a plant is not expected before 2017.

Key Challenges

Cost Uncertainties

12. As indicated by the evolution of our index (Figure 1), the cost of an ‘average energy project’, which has risen almost three times between 2003 and 2008, is expected to increase again, after having slightly dropped in the last review. The 25% upward trend underpinning the current review may be explained by two factors. The first is that project sponsors will be focusing on important projects, which mostly entail higher costs. The second factor is related to anticipated cost inflation, which is still tentative. The extent the latter factor is predictable is examined next by analyzing a typical project cost structure.

13. The most preponderant element in a project cost is the price of engineering, procurement and construction (EPC), which represents 70‐80% of the total cost of a typical large scale energy project. Using the criteria outlined by the Independent Project Analysis, the key contributing cost factors to EPC are the prices of factor inputs, contractors’ margins, and project risk premiums when assumed by contractors, as is the case of lump sum turnkey (LSTK) contacts.2 To these three factors we have added our own, which is the cost of ‘excessive largeness’. In order to cope with

2 In a move to cut project costs, some project sponsors within MENA region have had to rethink their contracting strategies, combining LSTK with Open Book Reimbursable Contracts (OBRC) through conversion agreements.

Box: Investments in the Power Generation Sector a

B1. As a result of high population growth rates and fast expanding urban and industrial sectors, many countries in MENA region have been struggling to meet rapidly increasing demand for power. However, compared to recent trends, projected demand is expected to be slightly curbed as a result of current economic contraction. Also, expectation of better load management and gradual phasing out of price subsidies could help rein in excess demand growth.

B2. Accordingly, power generation capacity is projected to grow at a relatively subdued rate of 7.7% for the period 2011‐15, resulting in an additional capacity of 99gw over that period. This increment, which represents 45% of the 2010 estimated aggregate capacity of 210gw, justifies the huge capital investment of $117 billion found in the present review. A regional breakdown of these projections (see Table below) shows that 49% of that expansion is expected in the GCC, which remains the fastest growing area. This should come as no surprise, taking into account its record rates of urbanization and the massive requirements for water desalination and air conditioning.

2009 Generation capacity (GW)

2009 Electricity

production (TWh)

Medium‐term annual growth (percent)

2011‐15capacity

addition (GW)

Corresponding capital requirements

(G$)

Maghreb 1 27.5 111.6 6.5 10.9 13.1Mashreq

243.1 231.6 7.5 20.2 25.1

GCC 3

87.8 391.5 8.5 48.0 53.0

Other Arab countries4

2.9 12.6 7.2 1.3 1.7Iran 43.0 196.5 7.0 18.5 24.1MENA Total 204.3 943.8 7.7 98.9 117.01Maghreb: Algeria, Libya, Mauritania, Morocco and Tunisia.

2 Mashreq: Egypt, Iraq, Jordan, Lebanon, PT and Syria.

3 GCC: Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the UAE. 4 Other Arab countries include Sudan and Yemen, but exclude Comoros, Djibouti and Somalia for lack of data.Compilations and projections by APICORP Research

B3. In implementing their investment programs, power generators will be facing the same challenges as the rest of the industry. As discussed in the main text, these pertain to cost, feedstock and funding. a See A Aissaoui, ‘Powering The Arab Economies in a New, More Challenging Environment’ (MEES, 25 January)..



unrelentingly rising costs, the major MENA project sponsors have sought to increase the scope and/or scale of their projects in order to lower unit costs and maintain an adequate return on invested capital. Anecdotal evidence suggests, however, that the economies of scope and scale of some large projects in the region have been offset by the diseconomies of the resulting complexities.

14. Reflecting the above components, Figure 3 shows a typical cost structure of a large scale energy project. Prices of factor inputs (steel, copper, cement, and so on), which represent some 45% of total project cost, are expected to rise again after having softened during the crisis, but at a pace more in line with that of major industrial materials and equipments than of raw commodities. Contractors’ margins are also likely to increase with the number of projects on the rise again. Furthermore, as the global credit crisis has forced an up‐pricing of risk, we should expect project risk premiums to remain relatively high. ‘Others’ denotes a miscellaneous component that tends to mirror the again rising general price inflation in the region. Hence it is hard to infer how up and for how long the overall cost trend is likely to be again, when combining all cost components.

Figure 3: Typical cost structure of a large‐scale energy project

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Feedstock Availability 15. Although a great number of MENA countries are endowed with substantial gas reserves, their supply situation is difficult to gauge. Different metrics must be developed to provide a clear picture. We have already tried an ‘optimal supply pattern’ (OSP) positioning.

3 Reflecting the structure and use of resources, OSP is defined as the one set of solutions that equalize the share of gas production in total petroleum production with that of gas reserves in total petroleum reserves. A simple Euclidean distance shows how far different countries are from that optimum. Obviously, countries ‘above’ the OSP line, as is currently the case of Bahrain, use more gas than they could afford. Countries ‘below’ that line, as is the case of all others, should have some room for more use of gas.

16. To find out which country is facing or is likely to face supply constraints, another metric is needed in the form of a reserve replacement ratio (RRR). RRR measures the amount of proved gas reserves added during the years relative to the amount of gas produced. As shown in Figure 4, except Bahrain and, surprisingly, Algeria, all other countries have a 20‐year average RRR of more than 1 (100%). Therefore, the gas supply constraints that the UAE, Kuwait and Saudi Arabia have arguably faced could not be caused by limited reserves but by either their production cost or by inadequate supply infrastructure.

3 This has been developed in: A Aissaoui, ‘Powering the Arab Economies in a New, More Challenging Environment’ (MEES, 25 January).

Figure 4: 20‐year Average Gas Reserve Replacement Ratio (RRR)

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Funding Accessibility 17. Cost uncertainties and feedstock availability are compounded by a marked shift in projects’ capital structure. In a context of a still tight credit environment, this is likely to complicate further corporate financing policies. We continue indeed to witness a trend towards a more equity oriented capital structure. Based on most recent deals, the average equity‐debt ratio in the oil‐based refining/petrochemical sectors has been 35:65. The ratio in the gas‐based downstream sector has been 40:60 to factor in higher risks of feedstock availability. In the power sector, the ratio has been reset to 30:70 to reflect lower leverage in independent power/water projects. On this basis, the resulting weighted average capital structure for the whole oil and gas supply chain is likely to be 57% equity and 43% debt for the period 2011‐15. This compares with the equity‐debt ratios of 54:46 found in the 2009‐13 review and 50:50 in the 2008‐12 review.

18. This trend poses new challenges for achieving the needed amount and mix of equity and debt . On the one hand, we have estimated that a prolonged period of low oil prices below $70/bbl will affect project sponsors’ ability to self‐finance upstream investments.

4 On the other hand, funding prospects for the still highly leveraged downstream will be even more daunting. The annual volume of debt of $41 billion for the next five years, which results from the actual capital requirements found in the current review and the likely capital structure highlighted above, remains comparable to the all‐time annual record of $39 billion achieved in the loan market prior to the credit crisis. Nowadays, such amounts of debt can hardly be raised owing to lesser credit availability, higher costs of borrowing and tighter lending conditions. And this is despite the move by some MENA public investment funds to tap governments’ net savings and step up their lending and involvement in the local debt market. Conclusions

19. Notwithstanding an uncertain global economic climate, growth of energy investment in MENA region is expected to resume, mostly driven by the power generation sector. In this context project sponsors face many of the same challenges: cost uncertainties, feedstock availability and funding accessibility, with the latter remaining the most critical. Due to global economic conditions, public resources have been inadequate and private investment has somewhat retreated. As a result, MENA governments face a difficult balancing act. They must step up to fill the current funding gap, but they must also provide the assurances critical to regaining private investment momentum.

4 This is the lower end of a price band of $70‐90/bbl adjusted for higher costs of production from EOR, heavy oil, bitumen, and oil shales. For underlying methodology see: A Aissaoui, ‘On Being Fair, Beautiful and Nearly Perfect: a Reflection on the Ethics, Economics and Politics of Oil Prices’ (MEES, 12 April).

Economic Commentary Volume 5 No 12 ‐ December 2010


MENA Natural Gas: A Paradox of Scarcity Amidst Plenty

This commentary has been prepared by Ali Aissaoui, Senior Consultant at APICORP. It is published concurrently in the Middle East Economic Survey dated 27 December 2010. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com.

1. One theme that stands out in a forthcoming book on Natural Gas in the Middle East and North Africa (MENA), by the Oxford Institute for Energy Studies (OIES), is “the rising concern about critical gas shortages in many countries in the region due to rapid growth of domestic consumption of natural gas and a muted and delayed gas supply response.”1 This main finding does underscore the apparent realities some of us have been pointing out in recent years. Indeed, although MENA region is endowed with substantial gas reserves, an increasing number of countries have been struggling with a dearth of supply. While the strategies to overcome identified constraints differ across countries, they all pose hard policy choices when it comes to reforming prices and subsidies and reining in excess demand growth. As progress will likely be slow and protracted, the book concludes that “a regional default model seems to be emerging based on increasing natural gas supplies through exploration and development (E&D).”

2

2. This conclusion begs two key questions. The first is how fast are MENA natural gas reserves depleting and in what way the resulting supply pattern is evolving. The second is whether the likely size of undiscovered resources is high enough to create sufficient opportunities for E&D. This commentary aims to explore and discuss these questions through a more extensive empirical analysis. We start by clarifying the assessment framework and origin of data.

Assessment Framework and Data

3. Our two‐part analysis deals with MENA natural gas reserves and resources. The first part is based on proved reserves as reported in BP’s Statistical Review of World Energy. The accepted definition for these reserves is the volumes that are estimated, with “reasonable certainty”, to be commercially recoverable from known reservoirs under current economic conditions, operating methods and government regulations. In contrast to proved reserves, which benefit from an extensive and systematic coverage, data for unproved reserves (probable and possible) remain partial. To avoid creating a gap between proved reserves and undiscovered resources, we adopt and extend the concept of “reserve growth”, which is defined next.

4. The second part of the analysis relies on assessment of undiscovered gas resources made by the US Geological Survey in 2000 (USGS‐2000) in 33 provinces, out of a total of 88 identified within MENA.

3 Our interpretation of the USGS assessment framework is depicted in Figure 1. Summing up already produced volumes, remaining reserves, reserve growth and undiscovered

1 Fattouh, Bassam and Stern, Jonathan. (Editors), Natural Gas in the Middle East and North Africa, Oxford Institute for Energy Studies [2011: forthcoming]. 2 Ibid. 3 U.S. Geological Survey (USGS 2000), World Petroleum Assessment, Region 2 Report: Middle East and North Africa.

resources (those estimated in 33 provinces) results into total MENA gas endowment. Reserve growth or growth‐to‐known reserves, as defined in USGS‐2000, is synonymous with field growth. It corresponds to the increases in estimated volumes of gas that typically occur through time as already discovered fields are developed and produced.

4 However, as elaborated in later sections, our inference of undiscovered gas resources in the not yet assessed 55 provinces, and the extension of reserve growth to volume growth of both discovered and yet to be discovered reserves, will mean a greater contribution to gas endowment.

Figure 1: USGS’s MENA Petroleum Assessment Framework

Produced

Assessed in 33 provinces (conventional)

Non‐assessed in remaining 55 provinces(conventional and unconventional)

Remaining

Known

Undiscovered

APICORP Research’s interpretation of USGS framework

Endowment Reserve growth(conventional)

Discovered

Reserves Depletion and Supply Pattern

5. At the start of 2010 MENA proved natural gas reserves were estimated at 84.5 trillion cu ms, representing 45% of the world’s total. The state of these reserves and their depletion are examined by using two simple but telling metrics: a long‐running reserve replacement ratio and a dynamic reserve life index. As we extend the analysis to the resulting supply trend a third metric, in the form of a distance to an optimal supply threshold, is introduced.

Reserve Replacement 6. The reserve replacement ratio (RRR) measures the amount of proved gas reserves added during the years relative to the amount of gas produced. Added reserves include revisions of previous estimates, improved recovery, extensions and new discoveries. Figure 2 shows that until the middle of the last decade, the increase in MENA aggregate production was supported by a very high reserve replacement rate of more than 8.5x (850%) with two prominent peaks. The first of 15.8x (1,580%) in 1992 stemmed mainly from Qatar’s claim of the North Field and culminated a few years later following Iran’s assertion of South Pars. The second of 13.1x (1,310%) in 2002 includes subsequent revisions of the two giant fields. In recent years the fall off of RRR to less than 2x (200%), even though double the world average, may give the alarming impression that MENA is running out of reserves. However, a more sober interpretation is that either reserve growth of existing fields has reached its peak or, considering the amount of undiscovered resources which will be discussed in the second part of this commentary, reinvestment in E&D has not been sustained.

4 For a broader discussion of the topic see Ahlbrandt, Thomas S. (2006), “Global Petroleum Reserves, Resources and Forecasts”, in Robert Mabro (Editor), Oil in the 21

st Century, Oxford University Press.

AP

ICO

RP

Re

se

arc

h



Figure 2: MENA And World’s RRR – Long Running Averages

0

2

4

6

8

10

12

14

16

18

20

1985

1990

1995

2000

2005

Reserve replacement ratio (RRR)

Long‐run ave. of MENA RRR

Long‐run ave. of World RRR

APICORP Research

UsingBP Statistical Review

7. We should expect the above aggregates to conceal considerable differences across countries. Indeed, Table 1 shows that in recent years Iran, Kuwait, Saudi Arabia, the UAE and Egypt, have continued to replace a large portion of their extracted reserves. By contrast, Qatar, Yemen, Libya, Iraq, Tunisia, Bahrain, Algeria, Oman and Syria, whose latest RRRs are less than 1x (100%), have failed to keep pace with production. Apart from Qatar, where the facts and circumstances should be considered in connection with the ongoing moratorium on further developments of the North Field, the situation appears unmistakably critical for other countries. In any case, failing to replace produced reserves can significantly shorten the life of remaining reserves, which is assessed next.

Table 1: Last 30‐Year, 10‐Year And 5‐Year RRR Averages

Last 30‐yr

Ave. RRR

Last 10‐yr

Ave. RRR

Last 5‐yr

Ave. RRR

Iran 14.38 5.42 3.64

Kuwait 3.02 2.61 3.39

Saudi Arabia 4.86 2.64 3.05

UAE 9.35 0.91 1.43

Egypt 5.85 3.10 1.15

Qatar 48.25 54.67 0.33

Yemen 0.04 0.16 0.16

Libya 4.21 2.99 0.05

Iraq ‐2.60 ‐2.60 0.00

Tunisia ‐‐ ‐‐ ‐0.01

Bahrain ‐0.65 ‐0.34 ‐0.08

Algeria 0.02 ‐0.02 ‐0.09

Oman 9.11 1.19 ‐0.13

Syria 4.07 0.69 ‐0.22

MENA 8.70 6.18 1.54

APICORP Research us ing BP Statis tica l Review

Reserve Life 8. The ratio of reserve to production (R/P) can provide a practical measure of reserve life. Applied to recent annual production (2009), it amounts to 146 years for the region as a whole compared to 63 years for the world. However, to avoid a static measure we need to make a non‐constant assumption about depletion rates. Figure 3 shows the ratio for MENA gas reserves as a function of future production growth. It indicates how many years current reserves would last in the absence of additional reserves. For a production growth of 6.6% a year, which corresponds to the last 10‐year average, future volumes from remaining reserves would last 36 years. This is still comfortably above the conventional 30‐year critical time horizon for reserve replacement strategic planning.

Figure 3: Reserve Life of MENA Gas Reserves

0

20

40

60

80

100

120

140

160

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10%

Reserves life (years)

Annual growth of gas production

APICORP Research

Extrapolationof past 10‐year average annual growth rate:

6.6%

146 years

36 years

9. As with the RRR metric, the R/P ratio is subject to significant variations across countries. Table 2 indicates a similar dynamic R/P ratio, which is computed by projecting each country production at a constant rate of growth equal to its past 10‐year historical rate. The resulting ratios for Iran, the UAE, Qatar, Kuwait, Algeria and Saudi Arabia are all higher than 30 years. However, apart from Syria, which is at the limit of this critical time horizon, all other countries are beneath it, with Bahrain being in the most unenviable situation.

Table 2: Static and Dynamic Reserve Life

Reserves Production Static

tcm bcm years Prod. growth years

Iran 29.610 131.2 226 9.0% 61

UAE 6.430 48.8 132 2.5% 58

Qatar 25.370 89.3 284 15.2% 58

Kuwait 1.780 12.5 142 4.0% 47

Algeria 4.500 81.4 55 1.0% 43

Saudi Arabia 7.920 77.5 102 5.4% 35

Yemen 0.490 10.3 48 2.5% 31

Syria 0.280 5.8 48 3.0% 29

Iraq 3.170 3.5 906 23.8% 24

Libya 1.540 15.3 101 13.1% 21

Egypt 2.190 62.7 35 14.5% 17

Oman 0.980 24.8 40 18.1% 11

Tunisia 0.045 4.3 10 0.5% 9

Bahrain 0.090 12.8 7 4.0% 2

Sudan 0.085 0.0 ‐‐ ‐‐ ‐‐

Morocco 0.045 0.0 ‐‐ ‐‐ ‐‐

Jordan 0.005 0.0 ‐‐ ‐‐ ‐‐

Total MENA 84.530 580.2 146 6.6% 36

APICORP Research using BP Statis tica l Review and own calculations

R/P RatioCurrent

Semi‐Dynamic

Supply Pattern 10 A further attempt at gauging the depletion of MENA reserves is by measuring the trend towards an optimal supply threshold (OST). Reflecting the structure and use of petroleum reserves (crude oil, NGLs and natural gas), OST is defined as the one set of solutions that equalizes the share of natural gas production in total petroleum production with that of natural gas reserves in total petroleum reserves. A simple Euclidean distance, expressed in percent, shows how far or near different countries are from that threshold. 5

11. This is illustrated in Figure 4 for MENA. The figure depicts the progress made by the region as a whole, decade after decade since 1970, towards the OST dashed line. Not being on the line means that the pattern of gas use (domestic consumption and export), by

5 This metric was first suggested by Ali Aissaoui in ‘Powering the Arab Economies in a New, More Challenging Environment’ (MEES, 25 Jan.2010).



not reflecting the structure of petroleum reserves, is sub‐optimal. In particular, being below the line means that natural gas has still some leeway for penetration in the aggregate energy balance. Conversely, being above the line indicates that natural gas is being used unsustainably.

Figure 4: MENA Gas Supply Path

0%

10%

20%

30%

40%

50%

0% 10% 20% 30% 40% 50%

Gas in total petroleum production

Gas in total petroleum reserves

1990 (12.3%)

2000 (14.7%)

APICORP ResearchUnderlying data from BP

2009 (10.1%)

1980 (20.4%)

1970 (21.6%)

12 The 2009 cross section in Table 3 confirms the above aggregate trend. Keeping progress towards the OST line should normally be encouraged; unless such a move is perceived too expeditious as a result of demand growing faster than additions to reserves. This appears to be the case of Iraq, the UAE, Libya, Saudi Arabia and Kuwait, whose distance to OST is lower than 5%. Therefore, each of these countries now runs the risk of not being able to keep its position once there. This is already the case of Bahrain, whose negative distance implies a position above the OST line. Such a position suggests that it is using more gas than it would possibly manage to supply in some future.

Table 3: MENA Countries Supply Positioning

Gas reserves

over

petroleum

reserves

Gas

production

over petroleum

production

Distance

to OST

Yemen 0.55 0.21 23.8%

Qatar 0.86 0.54 22.6%

Algeria 0.71 0.45 18.8%

Iran 0.59 0.36 16.5%

Syria 0.43 0.22 15.1%

Oman 0.54 0.36 13.2%

Egypt 0.77 0.60 11.8%

Tunisia 0.69 0.59 6.9%

Iraq 0.16 0.10 4.2%

UAE 0.31 0.25 3.9%

Libya 0.19 0.14 3.3%

Saudi Arabia 0.17 0.13 3.0%

Kuwait 0.11 0.08 1.6%

Bahrain 0.86 0.92 ‐4.3%

Total MENA 0.41 0.27 10.1%

APICORP Research us ing data from BP 2010

13. But our OST metric can be seen as a rather mechanistic interpretation of reality, which needs to be balanced with market and economic considerations. It may indeed be perfectly rational to under‐produce commercial gas if markets are not there or, taking account of the heavily subsidized domestic prices, the returns from investment are lower than can be obtained from other uses. The alternatives may include recycling more field gas to increase the supply of high export value NGLs or injecting gas into depleting oil fields to enhance their recovery.

Gas Endowment and Undiscovered Resources

14. So far we have concentrated on proved gas reserves. We now turn to undiscovered resources. As explained and illustrated earlier (Figure 1), to estimate these resources, USGS‐2000 focused on 33 provinces, out of a total of 88 identified within MENA. The 33 provinces are those having a history of E&D as of 1 January 1996 (the cut‐off date of USGS‐2000) or those deemed to be highly prospective. Undiscovered conventional gas resources were estimated at 39 tcm (mean value), 76% of which is non‐associated to oil. The corresponding volumes of NGLs, which lie beyond our scope, were separately reported.

15. The remaining, non‐assessed 55 provinces were probably considered as frontiers areas, high‐cost plays, either too remote or unconventional, hardly exploitable within the 30‐year time span (1995‐2025) adopted by USGS for its assessment. However, it should be noted that since the publication of the USGS study in June 2000, several significant gas provinces not included in the original assessment have been demonstrated offshore the Nile delta and the eastern Mediterranean. Furthermore, by focusing on conventional gas, the assessment overlooked tight, deep or contaminated gas areas which have since been developed in Algeria, Saudi Arabia and the UAE. The continuum of geologic conditions and the reach of conventional technologies can indeed blur the boundary between conventional and unconventional gas. This fuzziness, however, should not deter us from extrapolating USGS‐2000 assessment to the 55 non‐assessed provinces.

16. Obviously, any such an attempt raises serious methodological challenges. In contrast to USGS analysts, who based their assessment of undiscovered resources on geological insight, we have no choice but to infer endowment volumes by applying size distribution models only. The most widely used among such models are the log‐normal and fractal (power‐law) distributions, with the former tending to underestimate resources, and the latter to overestimate them. An alternative model, called the Variable Shape Distribution (VSD), has recently been applied by Roberto F Aguilera to non‐assessed provinces in order to estimate endowment volumes.

6 Contrary to other models, VSD does not presume any form of the distribution function, but allows actual data, in our case size and number of provinces, to determine the relationship (Figure 5).

Figure 5: MENA Gas Endowment, USGS (2000) and VSD

Source : Aguilera (2010)

1

10

100

1000

0.0001 0.0010 0.0100 0.1000 1.0000 10.0000 100.0000

Cumulative

Num

ber o

f Provin

ces

Size of Provinces (tcm)

USGS (2000) data for 33 provinces = 92.9 tcm

VSD for 33 provinces = 92.8 tcm (R2 = 0.98)

VSD for 88 provinces = 111.8 tcm

VSD for 88 provinces plus reserve growth (56%) = 174.3 tcm

17. Prof Aguilera’s findings in relation to MENA gas are depicted in Figure 5. Volumes (excluding reserve growth) of conventional gas in the 33 assessed provinces were estimated, on the USGS cut‐off

6 Aguilera, Roberto F., and Aguilera, Roberto. "Indexing and Normalizing Natural Gas Endowment", Paper presented to the SPE Latin American and Caribbean Petroleum Engineering Conference, Lima, 1‐3 December 2010.



date of 1 January 1996, at 93 tcm. This is obtained by adding USGS’s mean estimate of 39 tcm for undiscovered resources to 54 tcm of known reserves at that date. These volumes correspond to the area under the black diamonds (or the correlation‐fitted dark blue curve). The VSD model for 88 provinces (VSD‐88) points to higher volumes of some 112 tcm, corresponding to the area under the triangles. Furthermore, assuming a volume growth of 56%, which is justified next, a stretched VSD‐88 indicates an ultimate endowment of 175 tcm, corresponding to the area under the outer curve. While this is significantly higher than the endowment of a little more than 130 tcm resulting from USGS‐2000, it carries larger uncertainty.

18 The rate of 56%, which typically reflects past US reserve‐growth pattern, is the one taken in USGS‐2000 to “grow” world known gas reserves. However, as evaluated by USGS staff members in the mid‐2000s, the growth‐to‐known reserves within MENA was already higher (some 60%) after only 8 years (from January 1996 to December 2003) into their 30‐year span assessment.

7 Despite these findings, Prof Aguilera (2010) kept to the original rate of growth. However, he extended that rate to undiscovered volumes – an idea once contemplated by USGS – on the plausible assumption that increases in recovery factors would ultimately benefit both discovered and yet to be discovered fields. That being the case, it is important to note that a more conservative gas reserve growth than the one observed so far within MENA can still be justified on the expectation that recovery factors in the 55 non‐assessed MENA provinces (likely mostly unconventional gas) would be lesser than in the 33 assessed ones.

19. In any case, as applied, the VSD model generates aggregate volumes only. The usual method for allocating such volumes by country is pro rata of proved reserves. This, however, would give large reserve holders with few leftover provinces to explore, such as Qatar, an excessive share. Instead, our allotment is based on a weighted average of cumulative production, proved reserves and USGS‐2000 undiscovered resources. The most plausible results are obtained by placing increasing weights on the three sets of data. Finally, subtracting currently known reserves leads to undiscovered volumes, which hint at substantial E&D potential in Saudi Arabia, Iran, Qatar, Iraq the UAE and Algeria. To a lesser extent, opportunities appear to be also present in Oman, Jordan, Libya, Yemen and Egypt.

Table 4: Apportioning VSD‐88 Endowment

1. Cumulative

production

up to 2009

2. Proven

reserves

Jan 2010

3. USGS‐

2000

Undiscovere

4. Weighted

average of

1,2, and 3

5. Resulting

weighted

shares

6. Apportion

of VSD‐88

volumes

7. Endownt

after reserve

growth

8. Undiscovered

resources and

volume growth

(tcm) (tcm) (tcm) (tcm) (%) (tcm) (tcm) (tcm)

Saudi Arabia 1.318 7.920 19.286 12.503 25.2% 28.3 44.1 34.8

Iran 1.737 29.610 8.909 14.614 29.5% 33.0 51.5 20.2

Qatar 0.697 25.370 1.164 9.155 18.5% 20.7 32.3 6.2

Iraq (*) 0.067 3.170 3.399 2.767 5.6% 5.3 8.2 5.0

UAE 0.920 6.430 1.261 2.927 5.9% 6.6 10.3 3.0

Algeria 1.868 4.500 1.387 2.505 5.1% 5.7 8.8 2.5

Oman 0.243 0.980 0.956 0.845 1.7% 1.9 3.0 1.8

Jordan (*) 0.000 0.005 0.069 0.036 0.1% 1.1 1.7 1.7

Libya 0.251 1.540 0.598 0.854 1.7% 1.9 3.0 1.2

Yemen 0.034 0.490 0.620 0.479 1.0% 1.1 1.7 1.2

Egypt 0.582 2.190 0.579 1.117 2.3% 2.5 3.9 1.2

Sudan 0.000 0.085 0.439 0.248 0.5% 0.6 0.9 0.8

Bahrain 0.249 0.090 0.468 0.306 0.6% 0.7 1.1 0.7

Eritrea 0.000 0.000 0.309 0.155 0.3% 0.3 0.5 0.5

Kuwait 0.285 1.780 0.168 0.725 1.5% 1.6 2.6 0.5

Tunisia 0.064 0.045 0.202 0.127 0.3% 0.3 0.4 0.3

Syria 0.089 0.280 0.144 0.180 0.4% 0.4 0.6 0.3

Morocco 0.000 0.045 0.003 0.017 0.0% 0.0 0.1 0.0

Total MENA 8.404 84.530 39.961 49.558 100.0% 112.0 174.7 81.8

(*) Corrected from model output (more likely higher potential for Jordan, ʺto the detrimentʺ of Iraq)

APICORP using BP Statistical Review, USGS (2000) and Aguilera (adapted)

7 Klett, Timothy R. et al, “An Evaluation of the U.S. Geological Survey World Petroleum Assessment 2000”, AAPG Bulletin, The American Association of Petroleum Geologists, 6 April 2005.

20. As already noted, the bulk of the undiscovered resources are expected to be unconventional heralding a gas revolution similar to that taking place in the US. Thomas S Ahlbrandt, who led the USGS‐2000 assessment and is now among the world’s foremost experts in the field, considers that MENA, which has been very successful in conventional gas, “wins in terms of unconventional plays as well, largely due to the richness of [its] source rocks.”

8 The reason, he explains, is that “U.S source rocks are modest compared to the Silurian, Jurassic, Cretaceous and Tertiary source rocks in MENA.” In particular, he adds, “the Silurian is a huge unconventional Basin Center Gas Accumulations (BCGA) target in Algeria, Libya, Saudi Arabia, Iraq and Jordan.” That Saudi Arabia and Iran emerge in our assessment as the largest prospect for undiscovered resources and volume growth should not come as a surprise, since in his view, “South Pars and North Field are actually the conventional leg of a huge unconventional gas accumulation.” However, as enthusiastic as he is, he concludes with a word of caution: “Unconventional resources are expensive to develop and require pretty sophisticated geoscientists and supporting technology (fracturing equipment, adequate horsepower and rig capacity) all of which take time to build and deploy.” While the potential is there, the companies able to identify opportunities and take the risk will be distinctive. The key challenge is for MENA policy makers to create the right climate for such companies to invest and re‐invest.

Conclusions

21. In viewing a paradox of scarcity amidst plenty, this commentary has offered valuable empirical insights into the potential of MENA natural gas endowment by taking a closer look at both reserves and resources. On aggregate, proved reserves are substantial and their dynamic life fairly long. However, acceleration of depletion appears to have reached a critical rate for more than half our large sample of countries. If production continues not to be replaced in Algeria, Bahrain and to a lesser extent Iraq, this could lead to a supply crunch, obviously sooner for Bahrain than later. Oman, Syria and Tunisia would face a similar prospect in the absence of imports via respectively the Dolphin Pipeline (Qatari gas to the UAE and Oman), the Arab Gas Pipeline (Egyptian gas to Jordan, Syria and Lebanon), and the transit pipelines to Europe (Algerian gas to Tunisia and Morocco en passant). Furthermore, the supply patterns of the UAE, Libya, Saudi Arabia and Kuwait have reached a tipping point that should trigger urgent actions to curb demand.

22. The extension of the analysis to undiscovered resources and inferences from assessed to non‐assessed provinces has underscored a higher aggregate potential for reserve expansion than commonly assumed. On a country basis the resulting opportunities for E&D appear to be the greatest for Saudi Arabia and Iran, followed by Qatar, Iraq, the UAE, and Algeria. To a lesser extent, opportunities seem to be also present in Oman, Jordan, Libya, Yemen and Egypt. As these opportunities will be shifting towards unconventional gas, they will entail significantly higher costs of finding and development. Faced with structurally lower netback prices, MENA gas exporting countries have little choice but to raise domestic prices as part of a more conducive climate for investment and re‐investment. Obviously, this is even more so the case for the non‐gas‐exporting countries.

8 Tom Ahlbrandt’s email correspondence with the author dated 9 December 2010. For deeper insight into the topic see Ahlbrandt, Thomas S. (2010), “The Petroleum Endowments of the Total Petroleum Systems in the Middle East and North Africa Tethys”, The American Association of Petroleum Geologists

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