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APIC

ORP’s

Economic Commenta

ryArab Petroleum Investments Corporation

الشركة العربية لالستثمارات البترولية

Wrapping up Volume Seven 2012

December 2012

Economic Commentary

Volume Seven 2012

© Arab Petroleum Investments Corporation /42 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 Möbius strips can be generated by computer. The ones i l lustrating the front cover of this compilation were produced by former math Ph.D. student Nate Berglund (www.math.gatech.edu/~berglund).

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Volume Seven 2012


Foreword by Mr. Ahmad Al‐Nuaimi

Restating the Ambition, Purpose and Aspirations

Introduction

As with previous editions this annual compilation assembles into one single volume – the seventh of its kind ‐ all issues of APICORP’s Economic Commentary published during 2012. This offers the opportunity to highlight the key insights gained from our 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” as key drivers of energy investment and financing. 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 have given the Commentary broader reach and greater impact.

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

Ambition, Purpose and Aspirations

As we embark on Volume 8, the ambition, purpose and aspirations that underpin our research efforts and publications are worth restating and highlighting.

Ambition • 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 economic

policy debate.

Audience • Energy economists, professionals in the

petroleum and financing industries, and academics with potential interest in our region’s economic development.

• Policy analysts and policy makers .

Content • Detailed global and regional insights relevant to

APICORPs footprint and business focus: o Macro‐economic environment; o Energy investment trends; o Energy markets and prices; o Credit markets and interest rates.

Resources • Topical analytical essays and reviews from:

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

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Volume Seven 2012


Content

Page Foreword

3

Summary of Issues Issues

5

8

Vol 7 No 1 APICORP’s Review of MENA Energy Investment: Sustained Outlook despite Lingering Uncertainty

9

Vol 7 No 2 IEA’s World Energy Outlook: Review and Discussion of MENA Deferred Investment Case

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Vol 7 No 3 MENA Energy Investment in a Global Setting Assessment and Implications for Policy and Long‐term Planning

17

Vol 7 No 4‐5 MENA Power Reassessed: Growth Potential, Investment and Policy Challenges

21

Vol 7 No 6 Is the Anticipated Rise in Long‐term Oil Price Inevitable?

25

Vol 7 No 7 Global Trends in Renewable Energy Investment: A Review of the Frankfurt School‐UNEP’s Report and Discussion of the MENA Case

27

Vol 7 No 8‐9 Vol 7 No 10

Fiscal Break‐even Prices Revisited: What More Could They Tell Us About OPEC Policy Intent? MENA Energy Investment Outlook: Capturing the Full Scope and Scale of the Power Sector

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Vol 7 No 11 Vol 7 No 12

Strait of Hormuz: Alternate Oil Routes Not Enough MENA Natural Gas Endowment Is Likely To Be Much Greater Than Commonly Assumed

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Volume Seven 2012


Summary of Issues

Vol 7 No 1, Jan 2012: APICORP’s Review of MENA Energy Investment: Sustained Outlook despite Lingering Uncertainty

With stalled global recovery and ongoing regional political turmoil, MENA region continues to face the challenges of uncertain times. However, while lingering uncertainty hampers forecast, it does not significantly affect our assessment of energy investment for the five‐year period 2012‐16, which points to a sustained outlook. Driven by the oil downstream and the power sector the anticipated level of capital requirements of $525bn, even if still lower than potential investment, is the highest since the onset of the downturn caused by the global financial crisis. Nonetheless, investors and project sponsors are likely to endure many of the same problems. These include cost uncertainty, feedstock availability and fund accessibility, with the latter becoming most serious. Given the structure of capital requirement highlighted in the review, internal financing should not be a problem as long as the value of OPEC basket of crudes remains above $90/bbl. In contrast, external financing, which comes predominantly in the form of loans, is expected to remain relatively scarce in face of deteriorating loan supply and high cost of borrowing. Confronted with more pressing social demands, governments in the region may not be able to make up for funding shortfalls. Going forward, the best option should be for policy‐makers to strive to keep private investment from losing further momentum. Vol 7 No 2, Feb 2012: IEA’s World Energy Outlook: Review and Discussion of MENA Deferred Investment Case

In the WEO’s central scenario, required new oil and gas production from MENA to meet global demand to 2035 involves upstream investment of over $100bn per year. It is far from certain that such levels, which are comparatively higher that those resulting from our own review, will be forthcoming; neither in the medium term, as underscored in the Deferred Investment Case, nor in the longer term. In the medium term, which involves a bottom‐up analysis, the listed causes for delay are all likely, when not already a reality in some parts of the region. However, the key assumption that upstream investment is reduced by the same amount in all MENA countries is arguable. This generalization,

which is perhaps not required by the IEA’s WEM model, leads to an easier, but potentially misleading, interpretation of the results. The case of the core MENA producers and major contributors to global spare capacity should have been highlighted. As none of them has been affected by the region’s turmoil, this group should be able to pursue, unhindered, their planned investment programs.

In contrast to the medium term bottom‐up approach, the long term surely involves a top‐down process. Accordingly, the WEM model must have been led to treat MENA, or its core producers, as residual suppliers. This approach would seem analytically irrelevant as long as the IEA fails to integrate in its scenarios MENA producing countries’ own policy commitments and momentum. Otherwise, expectations of what the region should deliver would be vulnerable to the charge of being unrealistic.

Vol 7 No 3, Mar 2012: MENA Energy Investment in a Global Setting Assessment and Implications for Policy and Long‐term Planning

The content of this commentary is a speech transcript of APICORP’s Senior Policy Consultant Ali Aissaoui at the 13th International Energy Forum (Kuwait, 12‐14 March 2012). The relevant session was moderated by HRH Prince Abdulaziz Bin Salman Bin Abdulaziz Al‐Saud, Assistant Minister for Petroleum Affairs, Saudi Arabia, under the theme “Meeting Future Energy Demand: Planning and Investment for the Long‐term”.

The speech focused on the context and investment framework of the Middle East and North Africa. With ongoing turmoil, this region, which is potentially the center of gravity of global energy supply, has indeed become the subject of renewed attention with regard to energy security.

This topical perspective was developed along four lines: First, to highlight the major shifts in world’s energy demand and supply growth patterns; second, to review the energy supply investment needed to meet global demand; third, to look critically at the IEA’s ‘Deferred Investment Case’ of MENA upstream and its consequential impact on global oil and gas; and finally, to sum up the assessment of the context and investment framework and to suggest some implications for policy and planning.

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Volume Seven 2012


Vol 7 No 4‐5, Apr‐May 2012: MENA Power Reassessed: Growth Potential, Investment and Policy Challenges

As a result of high population growth, fast expanding urban and industrial sectors, increasing needs for air conditioning, and heavily subsidized electricity tariffs, many countries within MENA have been struggling to meet fast‐growing demand for electricity. With ongoing turmoil, catching up with unmet demand may be perceived as socially and politically more desirable. In the absence of active demand side management, this will entail capital investment of about $250bn for the period 2013‐17, 59% of which in new generation capacity and the remaining 41% in T&D. Investment of this scale will face many challenges, prominent among which are fuel and funding. The first stems from the scarcity of natural gas in key countries in the region and the opportunity cost of generating electricity using high‐value export oil products instead. The second results from the inadequacy of internal and external financing and the reluctance of many MENA governments to support cash‐strapped public utilities, which are committed to continuing to invest should the private sector be not forthcoming. Both fuel and funding challenges involve significant policy dilemmas that need to be addressed quickly and effectively.

Vol 7 No 6, Jun 2012: Is the Anticipated Rise in Long‐term Oil Price Inevitable?

As global oil demand increases, even if only moderately, and production from mature areas declines, finding and developing additional oil will definitely be more challenging in the future. However, the view that marginal cost, which drives long‐dated price at the back of the forward curve, should increase to stimulate additional supply is not immediately plausible. Despite (or because of) all the uncertainties, the likelihood, based not on empirical data but on reasoned judgment, is that rising marginal cost, and therefore long‐dated price, may not be inevitable.

Vol 7 No 7, Jul 2012: Global Trends in Renewable Energy Investment: A Review of the Frankfurt School‐UNEP’s Report and Discussion of the MENA Case

This review has been undertaken to gain insight into investment and financing trends in global renewable power, as well as the challenges facing the industry. The review has been further extended to include a discussion of trends and policies within a lagging MENA region and to bring into focus issues overlooked or misunderstood. While the general premise of the argument that the economics of renewables can be improved by factoring in opportunity costs is evident,

the determination of those costs in specific MENA cases is less obvious. Similarly, the idea that solar power can be fully deployed within MENA ignores the disincentives created by heavily subsidized electricity prices. These issues may after all be beyond the report’s scope; but surely, they are within the remit of MENA policy makers who have yet to reconcile them with their stated ambitious renewable energy goals.

Vol 7 No 8‐9, Aug‐Sept 2012: Fiscal Break‐even Prices Revisited: What More Could They Tell Us About OPEC Policy Intent?

In light of significant budgetary changes in key countries, we have provided an update of fiscal break‐even prices within OPEC. Keeping to our traditional two‐step analytical framework we have estimated current levels, then testing whether, if held constant in real terms, they could sustain future stable governments’ spending.

In the first part of the analysis we have re‐drafted the fiscal cost curve for OPEC member countries in an attempt to shed timely light on the likely individual and group policy behavior. On the one hand, it can be claimed that fiscal break‐even prices are dependable predictors of price preferences within the group. On the other hand, member countries’ failure to develop a common policy may be attributed to their heterogeneous and, for some, uncertain fiscal positions. This is no matter how close to OPEC’s weighted average fiscal break‐even price – currently in a range of $90‐110 per barrel – the most influential member, Saudi Arabia, may be.

In the second part we have focused on an inter‐temporal fiscal sustainability analysis, assuming OPEC – taken as a group – would be investing its surplus funds in financial assets. In doing so we have implicitly admitted that the bulk of budget spending are current expenditures that yield no long term returns. The consequence is that spending is implicitly kept low to enhance future financial returns. If we assume instead that government expenditures include a non‐negligible investment component then spending upfront may be a better course of action. This is valid provided the returns from domestic social and physical investment are higher than those from financial investment abroad. Using oil and gas revenues today to diversify their economies and progressively shift their reliance away from hydrocarbons may enable OPEC member countries to secure a more viable and sustainable economic development. Whatever their resulting spending patterns might be, it would affect their fiscal

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Volume Seven 2012


break‐even prices and hence their oil price preferences and production policy intents. The challenge that still remains is to translate these intents into a common and credible policy.

Vol 7 No 10, Oct 2012: MENA Energy Investment Outlook: Capturing the Full Scope and Scale of the Power Sector

APICORP’s 2012 review of MENA energy investment has been broadened in order to capture the full scope and scale of the power sector. Accordingly, MENA total energy capital investment is expected to amount to $740bn for the five‐year period 2013‐17. Compared to past assessments, which have been consistently revised to fully reflect adjustments in the power sector, investment appears to be on the rise again. However, in a context clouded by sluggish global economic growth and protracted regional socio‐political turmoil, capital requirements have mostly been driven by a catch‐up effect and unrelenting escalating costs. In this context, a little more than three quarters of energy capital investment are located in seven countries among the biggest holders of oil and gas reserves. Obviously, the geographical pattern has favored countries that have not faced the turmoil. On a sectoral level, adjustments in the rapidly expanding power sector have led to a more evenly distributed pattern between the three major value chains, i.e. oil, natural gas and power.

The review has also highlighted serious policy challenges. In addition to the deteriorating investment climate which forms the background of the review, three issues continue to confront investors: rising costs, scarcity of natural gas supply and funding limitations. Of the three, the latter is the most critical. Given the structure of capital investment stemming from the review, internal financing could only be secured if oil prices remain above OPEC’s fiscal break‐even price, which we have estimated to be around $100/bbl. In contrast, external financing, which comes predominantly in the form of loans, is likely to be daunting in face of dwindling lending resources. Faced with more pressing social demands, MENA governments may not be able to bridge the funding gap. Going forward policy makers in the region should focus their commitment on improving the investment climate and restoring investors’ confidence.

Vol 7 No 11, Nov 2012: Strait of Hormuz: Alternate Oil Routes Not Enough

The commentary explores the geopolitical importance of the Strait, Iran’s attempt to gain a strategic leverage point there and the extent the energy impact of a

looming crisis can be alleviated. We contend that alternate oil routes are not enough and that the IEA would have to shoulder alone the burden of dealing with the aftermath.

Vol 7 No 12, Dec 2012: MENA Natural Gas Endowment Is Likely To Be Much Greater Than Commonly Assumed

Except Iran, which has managed in recent years to add large volumes to its huge reserves, there is a tendency to discount MENA natural gas prospects. This may stem from the current perception of scarcity in parts of the region. Indeed an increasing number of apparently well‐endowed countries have been unable to balance their domestic natural gas market, shifting supply to oil products or filling the gap with imports, both at a very high opportunity cost.

Few studies have sought to shed light on this “MENA gas puzzle”. Unfortunately, they could not offer any deep insight into the region’s gas reserves and resources. Others have either ignored the issue or simply overlooked the most significant part of the region. This commentary is an attempt to contribute to filling that research gap. More specifically, it aims to offer an empirical analysis supporting the view that, notwithstanding the present critical supply situation, MENA natural gas endowment is likely to be much greater than commonly assumed.

Drawing on the latest BP’s Statistical Review of World Energy and USGS’s World Petroleum Resources Assessment, our findings confirm and extend our previous results. They show that on aggregate MENA proved reserves are substantial and their combined dynamic life is a little beyond the traditional 30‐year strategic planning horizon for E&D. However, reserve depletion in more than half our large sample of countries has critically neared ‐ if not already reached ‐ the point that warrants drastic actions to curb demand and support a supply response. The opportunities for the latter will be driven by a vast potential for reserve expansion. On a country‐by‐country basis the potential appears to be the greatest in Iran, Saudi Arabia and Qatar, followed by Iraq, the UAE and Algeria. Prospects also seem favorable in Egypt, Oman and Libya. As the opportunities available will be increased by unconventional gas, they will entail significant challenges. Confronting the region’s natural gas paradox ‐ a paradox of scarcity amidst plenty – requires both a demand and supply response. As far as the supply side is concerned, MENA policy makers need to rethink critically their E&D policies and the corresponding economic incentives.

Economic Commentary

Volume Seven 2012


Issues

Economic Commentary

Vol 7 No 1, January 2012

© Arab Petroleum Investments Corporation Page 9/42 Comments or feedback to: aaissaoui@apicorp‐arabia.com

This commentary has been prepared by Ali Aissaoui, Senior Consultant at APICORP, to serve as a review of business environment for the Corporation’s 2011 Annual Report.

1. 2011 will likely be remembered as the year of unprecedented political upheavals, sovereign debt crises and economic stagnation, not to mention extreme natural events such as the tsunami that crippled the Fukushima Daiichi nuclear power complex. In the Middle East and North Africa (MENA),1 discontent over inequity, corruption and ill‐governance has erupted suddenly, plunging many parts of the region into political turmoil. Equally unsettling have been the geopolitical tensions stemming from a further tightening of US and international sanctions over Iran’s nuclear program, which escalated in early 2012 to include the banning by the EU of vital petroleum trades. Adding to the uncertainty and anxiety, the eurozone debt troubles have re‐emerged as a prominent source of risk for global economic and financial recovery.

2. Although these unfolding developments carry far‐reaching implications for the region, they neither invalidate our framework analysis of energy investment nor the resulting outlook, as provided in September 2011.

2 It is important, however, to review our findings against evolving macroeconomic indicators and energy and credit market trends. Indeed, to the extent that economic growth, energy prices and interest rates are key determinants of investment and financing, the review should help clarify the outlook. Accordingly, the commentary is in three parts: the first highlights the current state of the economy and markets; the second validates our main findings so far; the third provides a timely update of the deteriorating funding conditions.

The Economy and Markets

Global and MENA Economies

3. The global economic recovery witnessed in 2010 and early 2011 suffered a set‐back thereafter, largely due to precipitous fiscal consolidations. To contain rising fiscal deficits, most governments around the world decided to cut down on spending, without waiting for private demand to respond to the fiscal stimulus measures they had resorted to. But this is only one dimension of the problem. According to the IMF’s World Economic Outlook, which was released in September 2011 under the theme “Slowing Growth, Rising Risks”,3 recovery has stalled as a result of two important fundamental macroeconomic imbalances. The first, which is endogenous, has to do with the poor response of households and firms to fiscal stimulus and monetary easing. The second, which is exogenous, has to do with current‐account‐deficit countries unable to take full advantage of higher foreign demand, while current‐account‐surplus countries failed to shift away from foreign to domestic demand. As a result, growth in 2011 is expected to be 6.2% for emerging market

1 MENA is here defined to include the Arab world and Iran. Energy investment in Sudan is kept inconsequentially aggregated until South Sudan decides on its membership in the Arab League. 2 ‘MENA Energy Investment: Broken Momentum, Mixed Outlook’, APICORP Research, September‐October 2011. 3 IMF, World Economic Outlook, September 2011.

countries and 1.6% for advanced economies. This translates into a weaker world growth of 3.8%, as compared to 5.2% in 2010. Looking ahead, “with intensifying strains in the euro area weighing on the global outlook”, the IMF revised its growth forecast at the end of January 2012 to reflect dimmer prospects (Figure 1).4 Indeed, with Europe virtually in recession and several other parts of the world slowing down significantly, the IMF finally aligned its growth assessment with the prevailing economic consensus. As a result, it sharply cut world growth to 3.3% in 2012, compared to 4% in its September forecast.

Figure 1: Overview of Global and Regional Growths

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4. In a context of stalling global recovery and continuing regional political uncertainties, the MENA region faces even greater challenges. To be sure, the region recovered fairly well from the downturn of 2008‐2009 as most countries managed, thanks to higher export‐based fiscal revenues, to build enough fiscal space to weather the global recession. As a result, growth accelerated in 2010 to 4.3% before dropping moderately to 3.1% in 2011. However, the unprecedented upheavals of 2011 left many countries vulnerable. Whether or not growth, which is expected to stagnate in 2012, can return to the pre‐crisis trend of about 5.5% by 2016, as assumed in Figure 1, depends on the affected countries recovering from the turmoil and the unaffected ones maintaining social and political stability. This is a major challenge, which hinges on the capacity of governments to rapidly develop more inclusive economic development agendas to address the socio‐economic problems that have been besetting them ‐ chief of which is providing jobs opportunities for a rapidly expanding young population.

The Credit Markets

5. To encourage banks to expand credit and stimulate the economy, both the US Federal Reserve (Fed) and the European Central Bank (ECB) ended up resorting to unconventional monetary policy measures. Because the Fed’s low interest rate policy, which had already reached its zero bound, is likely to be extended through the end of 2014, extra accommodation will continue to be provided. So far, this has taken the form of two rounds of ‘Quantitative Easing’ and, in September 2011, an ‘Operation Twist’. All such measures consist of purchasing assets on the open market, in the form of long‐maturity securities, with

4 “IMF Marks Down Global Growth Forecast, Sees Risk on Rise”, IMF Survey Magazine, 24 January 2012.

APICORP’s Review of MENA Energy Investment: Sustained Outlook despite Lingering Uncertainty

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Economic Commentary



the aim of lowering long‐term interest rates. Similarly, but to a lesser extent and by different rules, the ECB decided in December 2011 on a three‐year financing operations aimed at easing the funding pressures experienced by the European banks.

6. At the same time, six of the world’s most influential central banks (the Fed, the ECB, the Banks of England, Japan, Canada and the Swiss National Bank), announced coordinated actions to prevent panic about the eurozone debt crisis and a possible credit crunch whereby banks would stop lending to each other and pull back on loans to businesses. The Fed would cut the cost of borrowing US dollars to other central banks and they in turn will make it cheaper for their own banks to borrow these dollars by lowering interest rates on the so‐called ‘dollar swaps’. This operation is particularly aimed at the European banks, which have been struggling to raise funds on the money market amid growing doubt about their solvency due to their exposure to the debt of troubled eurozone countries.

7. All such operations have resulted in a significant augmentation in banks’ reserves. However, rather than stepping up their lending operations banks actually have used the proceeds to shore up their balance sheets. This is particularly the case of banks exposed to the euro sovereign debt. They have been busy deleveraging by both selling assets and reducing the amount they lend, including to each other. As a result, the interbank market has virtually dried up. This is well reflected in the dollar spread between Libor and the overnight index swap (OIS) ‐ a common measure of liquidity stress, which has indeed risen to a two‐year high of 50 bps at the end of 2011 and early 2012, compared to its normal level of about 10 bps (Figure 2).

Figure 2: Evolution of Libor‐OIS spreads

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8. In this context, the real economy has continued to face tight credit markets and relatively high borrowing costs. This is particularly the case in MENA where capital inflows ‐the bulk in the form of dollar loans ‐ have collapsed after banks reduced their country exposure limits or just pulled back from lending. As a result, after having remarkably recovered to $101bn in 2010, loans extended to infrastructure projects in the region have nearly halved to $57bn in 2011. Furthermore, the margins (over Libor) on these loans, while continuing to trend down from the 2009 peak of 285 bps, have averaged 210 bps in 2011 – still three times the pre‐crisis level of 70 bps. As discussed in greater detail later, we should expect unfolding events in the Eurozone and MENA region to affect both the volume and cost of capital required by the more capital intensive energy sector.

Oil and Gas Markets 9. Despite a weakening of the global economy, tight supplies and the loss of Libyan oil exports during most of 2011 have driven up oil prices by nearly $30/bbl above the level achieved in 2010. Given the dislocation between the major oil price benchmarks, this is expressed in Figure 3

by the evolution of the value of the OPEC basket of crudes, which averaged $107.46/bbl in 2011, only slightly below $111.36 for Dated Brent. Looking forward, we expect tight supply to continue putting upward pressure on prices. Conversely, should demand contracts far below supply, we assume that OPEC will be able to offset the resulting downward pressure on prices, keeping the value of its basket of crudes above our adjusted breakeven fiscal price of $90/bbl. 5

Figure 3: 2011 Tightening of the Oil Market

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APICORP Research using OPEC database, as of Jan 2012

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2011: Tightening of the marketin the wake of the 'Arab Spring'

10. In contrast to the oil market, natural gas markets have been characterized by relatively abundant supply. Current views on the prospects for global unconventional gas have developed a perception of large gas endowment that could lead to excess supply and lower prices. Already, fast growing production from shale gas reserves in the U.S. has resulted in the formation of a ‘bubble’, driving prices below $3/MBtu, a level equivalent to a mere 16% of WTI parity. Going forward, we expect global natural gas prices to keep deviating from oil parity and diverging between markets. Prices are likely to range between $4‐5/MBtu in fully liberalized markets with abundant domestic supplies (assuming a short‐lived US ‘bubble’) and $12‐15/MBtu in markets still relying on imports under traditional long term contracts.

MENA energy investment outlook

Overview of Key trends 11. The above key macroeconomic indicators and market trends have not invalidated our September review of MENA energy investment, which is mainly project‐based. Neither have the ongoing political turmoil in parts of the region and the resulting negative perceptions of the overall investment climate.

6 In this context our review of MENA energy investment for the five‐year

5 Adjusted following expansion of fiscal spending to appease or prevent unrest in MENA‐OPEC countries. The fiscal breakeven price was originally estimated at $77/bl in “Fiscal Break‐even Prices: What More Could They Tell Us About OPEC Policy Behavior?”, APICORP Research, March 2011. 6 This has been assessed and updated several times during 2011. The starting material is provided in ‘How the Changing Political Landscape in the Arab World Is Affecting Our Perception of the Energy Investment Climate?’, APICORP Research, April 2011.

Economic Commentary



period 2012‐16 continue to points to a sustained outlook. The resulting level of capital requirements of $525bn, even if still 15% to 20% lower than potential, is the highest since the onset of the downturn caused by the global financial crisis (Figure 4).

Figure 4: Rolling Five‐Year Reviews Of MENA Energy Investment

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Geographical Pattern 13. The country‐by‐country outlook is even more mixed. As for past reviews, the geographical pattern of investment broadly reflects the distribution of crude oil and natural gas reserves in the region. However, this time the country outlook has been greatly affected by the ongoing turmoil. Accordingly, Saudi Arabia (first in the ranking), the UAE (second) and Oman (eighth) have not only managed to bring back previously shelved projects but they have also been able to slate new ones for development (Figure 5). As a result, their anticipated investment is higher than the potential identified in the last review. To a much lesser extent lower league countries such as Morocco (16th) and Lebanon (17th) managed to do the same, while Mauritania (last in the ranking) has stayed put. In sharp contrast, all other countries are below their assumed potential. Obviously the falling off is more dramatic in the countries that have been affected by the turmoil so far, ie Egypt, Libya, Syria, Tunisia, Yemen and to a lesser extent Bahrain.

Figure 5: Country Pattern Across Previous And Current Reviews

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14. A little more than two‐thirds of the energy capital investment potential continues to be located in the same five countries, namely Saudi Arabia, UAE, Iran, Qatar and Algeria, none of which

has faced the sort of upheaval witnessed in the countries aforementioned. As already noted, Saudi Arabia tops the ranking with $141bn. In this country investment has mostly been generated by Saudi Aramco and SABIC as domestic private investors have continued to struggle to attract capital. Taking over from Iran, the UAE has become a distant second with $76bn worth of investment. Tighter international sanctions, and the retreat of foreign companies, have ended up taking a toll on Iran’s energy investment, which now stands at $58bn. Similarly, but for completely different reasons, investment in Qatar has also been on a sharp downtrend. With the moratorium on further development of the North Field still in place, energy capital requirements have plummeted to $41bn. The same low amount is found in Algeria where investment recovery seems to be slower than progress in repairing broken governance within Sonatrach.

15. Finally, it is worth highlighting the peculiar circumstances of Kuwait and Iraq, where energy investment has remained chronically below potential. In Kuwait the problem seems to be one of policy paralysis induced by indecisive politics. As a result, major components of the upstream program and key downstream projects such as the giant al‐Zour refinery are still to be decided. In Iraq there seems to be no major disagreement about the vital need to achieve the full development of the oil and gas sectors. However, for the commitment to be credible, the federal government needs to pass a long‐awaited package of hydrocarbon legislation and provide durable solutions to recurring security threats and logistic complications.

Sectoral Pattern 16. Of the $525bn capital requirements in MENA region for the period 2012‐16, the oil value chain accounts for 42%, the gas value chain for 34% and the remaining 24% represent the oil and gas fuelled power generation sector (expenditures for nuclear power generation is implicit in the UAE’s case).

7 As shown in Figure 6, the most salient link is the oil downstream where investment is mostly driven by Saudi Aramco’s program of large scale integrated refining/petrochemical facilities. In contrast, investment in the gas downstream link has declined as a result of Qatar’s moratorium and the consequent pause in its LNG and GTL expansion program.

Figure 6: Sectoral Pattern Across All Reviews

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7 While Iran’s first nuclear power plant, the Bushehr 1 reactor, was officially inaugurated in August 2010 (to be only partially operational in late 2011), Abu Dhabi’s first such a plant is not expected before 2017.

Economic Commentary



17. The power/water sector has remained a key, steady driver of investment for MENA energy sector. Contrary to other segments of the industry where the review of investment is project‐based, the assessment of investment in this sector is growth‐based. However, despite sustained expansion, which is well reflected in Figure 6, power supply has fallen short of requirements. As highlighted in the Box below, to catch up with unmet potential demand, this sector needs massive capital whose funding will be most challenging.

Major Challenges

Cost Uncertainties and Feedstock Availability 18. As indicated by the evolution of our index (Figure 4), the cost of an ‘average energy project’, which has risen almost three times between 2003 and 2008, has resumed its upward trend after declining significantly in the middle of the global financial crisis. However, the relatively moderate 12% upward trend underpinning the current review should not mislead. The extent project costs are predictable depends on the outlook for the price of engineering, procurement and construction (EPC) and its components. These include the prices of factor inputs, contractors’ margins, project risk premiums and an element that mirrors general price inflation in the region. Despite efforts to

quantify in a meaningful way each of these parameters, we have found it difficult to infer how up and how long the overall cost trend is likely to be when combining all components.

19. As far as the supply of feedstock (natural gas and ethane) is concerned, we have already discussed at sufficient length the issue. Suffice it to refer to our main findings.8 While aggregate MENA proved gas reserves are substantial and their dynamic life expectancies are fairly long, acceleration of depletion appears to have reached a critical rate for more than half the gas‐endowed countries. If production continues not to be replaced in Algeria, Bahrain and to a lesser extent Iraq (the latter can still increase supply by cutting down flaring gas), this can lead to a supply crunch, obviously sooner for Bahrain than later. The UAE, Oman, Syria and Tunisia would face a similar prospect in the absence of additional 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 Saudi Arabia and Kuwait have reached a tipping point that should trigger further actions to secure supply.

Deteriorating Funding Conditions 20. Uncertainties surrounding project costs and feedstock supplies are compounded by a sudden deterioration of funding conditions, which is likely to complicate further the strategic decisions energy corporations in the region make with respect to investment and financing. To be sure, the upstream and midstream sectors should continue to rely on internal financing, either from state budget allocations or from corporate retained earnings. In contrast, transactions in the downstream sector are likely to continue to be structured with higher equity content. Indeed, in a context of widespread deleveraging, the downstream, which normally exhibits a ratio of 70% debt and 30% equity (70:30), has exhibited higher equity levels. In the oil based refining/petrochemical link the debt‐equity ratio has been 65:35. The ratio in the gas based downstream link has been 60:40 to factor in higher risks of feedstock availability. In the power sector, the ratio has been reset to 70:30 to reflect much less leveraged IPPs and IWPPs. As a result, the weighted average capital structure for the oil and gas supply chains is found to be 43:57 (Figure 7).

Figure 7: MENA Energy Investment and Financing

UpstreamC: $152bnL: 0:100 Aggregate

capital required and

capital structureC: 525bnL: 43:57

Retained earnings

APICORP Research

Medium and long term loans

Bonds or sukuks

Common stocks

State budget

allocationDownstream

C: $220bn

L: 60:40

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8 Ali Aissaoui, ‘MENA Natural Gas: A Paradox of Scarcity Amidst Plenty’ (MEES, 27 December 2010).

Box: MENA Investment in the Powerr Generation Sector

B1 In the current socio‐political context, power/water has emerged as a critical sector featuring prominently on top of MENA policy agendas. As a result of high population growth, record levels of urbanization, sustained economic growth and pressing needs for air conditioning and sea water desalination, many countries in the region have been struggling to meet demand. They now face an even steeper uphill struggle as phasing out price subsidies to rein in excess demand growth has become extremely tricky. B2. Accordingly, power generation capacity is projected to continue growing at an unrelenting rate of 7.7% per year during the period 2012‐16. The resulting five‐year capacity increment of 106 GW, half of which is in the GCC area, translates into a $126bn investment (see table below). 2010

capacity

generation (GW)

2010electricity

production (TWh)

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growth (%)

2012‐2016capacity

addition (GW)

2012‐2016capital

requirements (G$)

GCC 1 96.4 429.8 8.5 52.7 58.2Mashreq 2 46.1 247.9 7.6 21.7 27.0

Maghreb 3 29.2 118.4 6.2 10.8 13.0Other countries

4 3.1 13.5 7.2 1.4 1.8

Iran 46.0 210.3 7.0 19.8 25.8MENA region 220.8 1,019.9 7.7 106.4 125.8

1 GCC: Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and United Arab Emirates (UAE). 2 Mashreq: Egypt, Iraq, Jordan, Lebanon and Syria. 3 Maghreb: Algeria, Libya, Mauritania, Morocco and Tunisia. 4 Other countries include Yemen and Sudan.

Compilations and projections by APICORP Research

B3. Raising such large amounts of capital will be most challenging. With domestic and foreign private investment somewhat retreating, governments in the region must pursue two tracks simultaneously and with determination. On the one hand, and as long as the allocation of public resources reflect their policy priorities, they should step in to fill some of the financing gap. On the other hand they have to step up their efforts to provide the assurances critical to regaining the lost momentum of private investment (IPPs/IWPPs).

Economic Commentary



21. This structure of capital is comparable to the world’s average of nearly 40:60 for all groups of firms, as supported by empirical analysis of the World Bank’s Enterprise Surveys (WBES) dataset.9

22. Internal or self‐financing of the 57% funds required will be a function of how much growth capital MENA energy corporations generate from their own income, which depends for most of them on international oil prices and their dividend policies. The upstream and midstream links of the oil and gas supply chain are likely to continue to be financed through retained earnings by the national oil companies (NOCs) and their partners the international oil companies (IOCs). In addition, as long as the value of OPEC basket of crudes remains above our revised fiscal break‐even price of about $90/bbl, NOCs can expect to complement funding from government budgets.

23. The remaining 43% of the funds required may be sourced from the equity capital market (external equity), the debt capital market (bonds or sukuks) and the banking industry (loans). Whenever possible, MENA energy corporations and their local and international partners would consider using the full range of such financing instruments. Unfortunately, their choice has so far been limited to almost only bank loans. As noted earlier, such loans have collapsed for all industry groups from $101bn in 2010 to $57bn in 2011, ending up representing a mere 1.3% of the world global loans of $4,307bn. In this regard, it is also worth noting that while external financing for the world’s ‘energy’ group represented 23% of the world’s all industry groups, that for MENA accounted for 40% due to the more fixed‐asset‐intensive nature of the region’s investment. The GCC area was responsible for 77% of all MENA external financing in 2011 resulting in a higher share of 47% (Table 1).

Table 1: Global and Regional External Financing in 2011

Vol. ($bn) %Share Vol. ($bn) %Share %All Ind.

World 4,306.6 100.0% 991.2 100.0% 23.0%

MENA within World 56.8 1.3% 22.7 2.3% 40.0%

GCC within MENA 43.9 77.3% 20.6 90.7% 46.9%

APICORP Research, us ing IMF and Dealogic

All industry groups Energy' group

24. The needed annual volume of debt of $45bn, which results from the capital requirements found in the current review and the likely capital structure highlighted in Figure 7, is of the same order as the record of $44bn achieved in MENA loan market in 2010. It is, however, double the level of $23bn finally secured in 2011 (Figure 8). Raising the required amounts of debt in the current context of collapsed loan market and persistently high cost of borrowing will be hardly achievable. The resulting shortfall could be even larger in 2012 and beyond if MENA Public Investment Funds fail themselves to raise capital. These Funds, which have stepped up their involvement in the local loan market in recent years, may indeed be denied support by governments now confronted with more competing social demands for public funds.

9 Reported by Asli Demirguc‐Kunt in a post titled “How Do Firms Finance Investment?” dated 6 April 2010, on blogs.worldbank.org

Figure 8: Evolution Of Loans To MENA Energy Sector

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Conclusions

25. With stalled global recovery and ongoing regional political turmoil, MENA region continue to face the challenges of uncertain times. However, while lingering uncertainty hampers forecast, it does not significantly affect our assessment of energy investment for the five‐year period 2012‐16, which points to a sustained outlook. Driven by the oil downstream and the power sector the anticipated level of capital requirements of $525bn, even if still lower than potential investment, is the highest since the onset of the downturn caused by the global financial crisis. Nonetheless, investors and project sponsors are likely to endure many of the same problems. These include cost uncertainty, feedstock availability and fund accessibility, with the latter becoming most serious. Given the structure of capital requirement highlighted in the review, internal financing should not be a problem as long as the value of OPEC basket of crudes remains above $90/bbl. In contrast, external financing, which comes predominantly in the form of loans, is expected to remain relatively scarce in face of deteriorating loan supply and high cost of borrowing. Confronted with more pressing social demands, governments in the region may not be able to make up for funding shortfalls. Going forward, the best option should be for policy‐makers to strive to keep private investment from losing further momentum.

2011 Issues of APICORP’s Economic Commentary

‘Global and MENA Energy M&A : An Investment of Choice or of Last Resort?’, November‐December 2011

‘MENA Energy Investment: Broken Momentum, Mixed Outlook’, September‐October 2011.

‘READERS’ FORUM ‐ Shifting Business Models and Changing Relationship Expectations of IOCs, NOCs and OFSCs’, August 2011.

‘Financing MENA Energy Investment in a Time of Turmoil’, June‐July 2011.

‘WEF’s Repowering Transport Project – Review and Implications’, May 2011.

‘How the Changing Political Landscape in the Arab World Is Affecting Our Perception of the Energy Investment Climate?’, April 2011.

‘Fiscal Break‐even Prices: What More Could They Tell Us About OPEC Policy Behavior?’, March 2011.

‘APICORP’s Annual Review of the Arab Economic and Energy Investment Outlook: Still‐strong Fundamentals Despite Heightened Uncertainty’, January‐February 2011.

Economic Commentary Volume 7 No 2, February 2012

© Arab Petroleum Investments Corporation /42 Comments or feedback to: aaissaoui@apicorp‐arabia.com

IEA’s World Energy Outlook: Review And Discussion Of MENA Deferred Investment Case

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 20 February 2012. The author wishes to state that there is no conflict of interest between his being a peer‐reviewer for the IEA’s WEO and the present review and discussion. The opinions expressed are his own. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com

1. A few months ago, in November 2011, the International Energy Agency (IEA) released its annual World Energy Outlook (WEO).1 This 660‐page report provides analyses and insights into energy demand, production, trade and investment for the next 25 years. It further highlights the implications of a possible delay in upstream investment in the Middle East and North Africa (MENA),

2 which is set to supply the bulk of the growth in global oil output to 2035, as well as a substantial amount of natural gas. In a way, this is a replication of a previous study conducted in the 2005 edition of the WEO. The difference is that today’s MENA context makes the underlying assumptions more likely to occur if not already occurring.

2. The implications of such a delay are serious enough to warrant a review and discussion of the IEA’s main findings that could help better inform the debate on policy and investment. This is done in three parts. The first explains how our review and discussion fit within the broader IEA framework analysis. The second highlights the prospects for energy demand and the necessary investments to ensure supply to the market. The third discusses the impact of a possible shortfall in MENA upstream investment, before offering some concluding remarks.

Putting The Scope Review Into Perspective

3. The IEA analyses are performed using the World Energy Model (WEM). 3 This tool makes use of a wide range of econometric and simulations programs to project global energy trends and explore the environmental impact of energy use, as well as the effects of policy actions and technological change. It further derives the investment needed in the energy supply industry.

4. The 2011 projections have been prepared under three policy‐based scenarios. The Current Policies Scenario assumes very conservatively that no new policies are implemented. The 450 Scenario assumes strong policy measures to prevent global temperatures from rising more than 2°C above pre‐industrial levels. Somewhere in between is a more plausible, though still uncertain New Policies Scenario. This central scenario takes account of announced policy commitments and plans. Each scenario involves a set of non‐policy assumptions. While demographic and economic assumptions are common to all scenarios, international fuel prices and technological developments differ for each.

5. As shown in Figure 1, in addition to the assumptions block, the model is made up of six modules: final energy demand; transformation processes (power generation, refinery, etc); fossil

1 IEA, World Energy Outlook, Paris: November 2011. 2 MENA is made up of two groupings used by the IEA’s WEM model: the Middle East (Bahrain, Iran, Iraq, Jordan, Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, Syria, the United Arab Emirates and Yemen) and a sub‐grouping of Africa composed of Algeria, Egypt, Libya, Morocco and Tunisia. 3 IEA, ‘World Energy Model, Methodology and Assumptions’, 2011.

fuel supply; regional energy balance; CO2 emissions; and investment. As the impact of deferred MENA upstream investment is a key focus of the 2011 WEO, specific assumptions have been fed back into the supply module. By keeping all other assumptions unchanged, several iterations have been performed to determine the new oil and gas prices that bring global supply and demand into balance.

Figure 1: World Energy Model Overview

Reduced MENAInvestment Feedback

Source: IEA World Energy Model 2011 (adapted from original to show reduced MENA investment feedback)

6. The impact of lower investment and output on international oil and gas prices, energy markets and energy trade between producing and consuming countries will be discussed in the third section of this review. Before that, it is worth examining, even if briefly, the IEA’s main findings of energy trends and investment.

Trends In Energy Demand And Supply Investment

7. In the New Policies Scenario (NPS), to which we restrict the rest of our review and discussion, global energy demand increases by nearly 40% between 2009 and 2035. Driven primarily by population and economic expansion, this growth is accompanied by a major shift in geographical patterns. As a result, non‐OECD countries will be responsible for 90% of the growth, with China and India alone accounting for half the total increase (Figure 2).

Figure 2: Growth In Global Energy Demand In The NPS

Source: IEA World Energy Outlook 2011

8. While world demand grows for all energy sources, the share of fossil fuels (coal, oil and natural gas) in global primary energy demand falls from 81% in 2009 to 75% in 2035. Despite growing faster than any other source of energy, renewables (hydro, biomass and others) remain below each of the three fossil fuels in 2035 (Figure 3). Finally, with diminishing prospects in the wake of the Fukushima disaster, nuclear power, which is mostly led by China, India and Korea, ends up with a lower level of output than previously anticipated.

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Figure 3: World Primary Energy Demand By Fuel In The NPS


9. Oil and natural gas develop distinctive outlooks. Driven by transport, oil is expected to remain the primary source of energy for the world economy. However, global oil demand increases at the lowest average annual rate of 0.6%, from 84.1mn b/d (3,987mn tons of oil equivalent – mtoe) in 2009 to 99.4mn b/d (4,645 mtoe) in 2035. Natural gas nearly catches up with coal as it ultimately wins in the competition for power generation. As a result, global gas demand increases by a rate three times higher than that of oil, from 3.07 tcm (2,539 mtoe) in 2009 to 4.75 tcm (3,928 mtoe) in 2035. MENA is expected to supply the bulk of the growth in oil output to 2035. As the increase in production from the region is put at more than 90% of the required growth, the region’s share in global production raises from 36% in 2010 to 43% in 2035. The increase in the region’s natural gas production is 29% of the required global growth, which raises only modestly the region’s share from 19% in 2010 to 22% in 2035.

10. Based on the above projections, a total cumulative investment in energy infrastructure of $37.9 trillion (2010 dollars) is needed to balance supply and demand over the next 25 years. As detailed in Figure 4, investment in the oil supply chain is projected to be $10.0 trillion, representing 26% of total; the gas supply chain $9.5 trillion representing 25% of total; coal $1.2 trillion representing 3% of total; and biofuel $0.4 trillion representing 1% of total. The highest share is that of the power sector (generation, transmission and distribution), which amounts to $16.9 trillion representing 45% of total.

Figure 4: Cumulative Investment In Energy Supply In The NPS


11. In compiling the regional distribution of energy investment, MENA share proved surprisingly difficult to establish. In the current WEO, MENA is an ad hoc grouping used only in the “Deferred Investment Case”, which deals exclusively with oil and gas upstream. However, additional data communicated by the

WEO team put MENA cumulative energy investment at $3.9 trillion (2010 dollars), 45% of which in the oil sector, 34% in the gas sector and 21% in the power sector.

12. Investment in MENA oil and gas upstream amounts to $2.7 trillion (2010 dollars) for the next 25 years and translate into an average annual investment of $100bn from 2011 to 2020 and $115bn from 2021 to 2035. The medium term levels are inferred from a bottom‐up approach built, inter alia, on an extensive survey of companies’ data, prior to the region’s turmoil. They are comparatively much higher than those suggested by our latest review.

4 Yet, MENA share in global upstream investment – some 17% in the WEO – appears somewhat low in light of the region’s resource endowment. Indeed, MENA holds 59% of the world’s proven reserves of crude oil and condensate, but only contributes 36% of global oil output. Similarly, while holding 43% of proven natural gas reserves, it only accounts for 19% of world gas output. One explanation for the relatively modest investment share, compared to potential, is that MENA upstream oil and gas generally requires comparatively less capital due to lower costs of finding, developing and producing. This is still the case despite costs having soared in recent years.

13. Cost inflation is the most important factor driving the increase in energy investment. The WEO has established that worldwide the costs of developing oil and gas infrastructure have at least doubled during the last decade, largely due to increase in the cost of material, personnel, equipment and services. Furthermore, in the upstream sector, costs have been found to correlate closely to both oil prices and the levels of exploration and development activities (Figure 5). This trend is fairly similar to our own findings. In the context of MENA, we have found that the cost of an ‘average energy project’ has doubled since 2003. Our interpretation, however, is that the increase stems from the concurrent inflation of the main cost components of engineering, procurement and construction, including the cost of input factors, contractors’ margins, project risk premiums and the cost of what we have dubbed ‘excessive largeness’. In any case, even if it is difficult to infer a clear‐cut direction from the above, it seems likely that project costs will continue rising.

Figure 5: IEA Upstream Investment Cost Index


14. While projected MENA upstream investment appears low, the required production from the region, as noted earlier, is considerable. Understandably, the IEA is concerned that a shortfall in investment could limit such a production with far‐reaching impacts on global energy.

4 Ali Aissaoui, ‘MENA Energy Investment: Broken Momentum, Mixed Outlook’, MEES, 3 October 2011.



The Impact Of A Deferred Upstream Investment

15. Accordingly, the ‘Deferred Investment Case’ (DIC) analyses how global markets might evolve should MENA upstream investment fall short of what is required in the New Policies Scenario (NPS) over the medium term. The key assumption is that upstream investment is reduced by one‐third across MENA.

16. The likely causes for deferred investment include conservative depletion policies, constraints on financing, renegotiation of upstream agreements, international economic sanctions, higher perceived risks stemming from political instability; and in case of conflict, durable loss of production due to serious damage to infrastructure. On this basis, the impacts of the DIC have been measured in terms of changes in prices, demand, production and trade, as summarized next.

17. In terms of prices, the average IEA crude oil import price, which proxies international oil price, increases rapidly in the short to medium term, as the investment shortfall becomes apparent to the market. As shown in Figure 6, oil price peaks to $150/B (2010 dollars) in 2016‐17 (equivalent to $176/B in nominal terms), before converging gradually towards that of the NPS. More complex to analyze and predict, gas prices are also expected to increase, though not to the same extent as oil.

Figure 6: Average Oil Price In The NPS And DIC


18. In terms of demand, sharply higher oil prices encourage conservation and, in the longer term, a switch to alternatives, increasingly largely in the transport sector. As a result, global oil demand increases by a mere 0.9mn b/d to 88.0mn b/d in 2015, which is 3.2mn b/d lower when compared with the NPS. Thereafter, although demand rise steadily to 97.8mn b/d in 2035, it remains 1.6mn b/d below the NPS.

19. In terms of production, lower investment in MENA reduces global oil production by 3.8mn b/d at its 2017 peak and 1.5mn b/d in 2035, compared with the NPS. The shortfall in MENA production, of some 3.4mn b/d in 2015, peaks at around 6.2mn b/d in 2020 by which time it is partly compensated by an increase in non‐MENA production of 3.2mn b/d. While MENA is expected to recover its 2010 production by 2023, it never attains the level anticipated in the NPS since production in 2035 is still 1.2mn b/d lower.

20. Finally, in terms of trade, the impact on MENA exporters, non‐MENA exporters and non‐MENA importers is uneven. Because of the limited scope for reducing domestic demand, the drop in MENA export volumes is equivalent to the decline in production. However, in the period up to 2018, MENA cash flows (export revenues above costs) are higher as a result of lower export volumes being more than offset by higher prices. But because

MENA countries lose market share through the projection period, their cumulative cash flows are roughly the same: $16.7 trillion (2010 dollars) in the DIC against $17.0 trillion in the NPS (Figure 7). This means that the gain in cash flows during the period up to 2018 is virtually offset by the loss in the period after. Obviously, non‐MENA exporting countries enjoy higher revenues as a result of higher prices and possibly higher production to make up for MENA shortfall. Their export cash flows reach $8.8 trillion, 60% higher than in the NPS. Finally, the impact on importing countries is mixed. On the one hand, their oil and gas import bills increase by 10% to more than $46 trillion, since oil price increases are not offset by both reduced demand and increased domestic production. On the other hand, and this should have been emphasized by the IEA, their energy security improves as a result of more diversified supplies. It should be noted that the above cash flows have not been discounted to present values. While discounting would have led to substantially different results and policy implications, the choice of a discount rate would have probably been problematic.

Figure 7: Export Cash Flows And Import Costs In The NPS And DIC


Concluding remarks

21. In the WEO’s central scenario, required new oil and gas production from MENA to meet global demand to 2035 involves upstream investment of over $100bn per year. It is far from certain that such levels, which are comparatively higher that those resulting from our own review, will be forthcoming; neither in the medium term, as underscored in the Deferred Investment Case, nor in the longer term. In the medium term, which involves a bottom‐up analysis, the listed causes for delay are all likely, when not already a reality in some parts of the region. However, the key assumption that upstream investment is reduced by the same amount in all MENA countries is arguable. This generalization, which is perhaps not required by the IEA’s WEM model, leads to an easier, but potentially misleading, interpretation of the results. The case of the core MENA producers and major contributors to global spare capacity should have been highlighted. As none of them has been affected by the region’s turmoil, this group should be able to pursue, unhindered, their planned investment programs.

22. In contrast to the medium term bottom‐up approach, the long term surely involves a top‐down process. Accordingly, the WEM model must have been led to treat MENA, or its core producers, as residual suppliers. This approach would seem analytically irrelevant as long as the IEA fails to integrate in its scenarios MENA producing countries’ own policy commitments and momentum. Otherwise, expectations of what the region should deliver would be vulnerable to the charge of being unrealistic.

Economic Commentary Volume 7 No 3, March 2012


MENA Energy Investment in A Global Setting Assessment and Implications for Policy and Long‐term Planning

A Not So Simple FrameworkThe content of this commentary is a speech transcript of APICORP’s Senior Consultant Ali Aissaoui at the 13th International Energy Forum (Kuwait, 12‐14 March 2012). The structure of this new edition of the so‐called producer‐consumer dialogue is detailed at the end of the commentary. The relevant session was moderated by HRH Prince Abdulaziz Bin Salman Bin Abdulaziz Al‐Saud, Assistant Minister for Petroleum Affairs, Saudi Arabia, under the theme “Meeting Future Energy Demand: Planning and Investment for the Long‐term”.

Slide 1

MENA Energy Investment in A Global SettingAssessment and Implications for Policy and Long-term Planning

Aissaoui, Senior Energy Policy Consultant

Arab Petroleum Investments Corporation

13th International Energy Forum - Kuwait, 12-14 March 2012

Panel 1: “Meeting Future Energy Demand: Planning and Investment for the Long-term”

1. Your Royal Highness, Excellencies, Ladies and Gentlemen good evening. It’s an honor and a really exciting challenge to be tasked with lending support to your discussion tonight. Thank you very much to the organizers for giving me this opportunity. In the course of researching the theme of this session, I realized that even in restricting myself to the traditional determinants of investment, i.e. demand, price, cost, and the opportunity cost of capital, the theme was too broad to distill in a 10‐minute presentation. Instead, I was encouraged to focus on the context and investment framework of the Middle East and North Africa. With ongoing turmoil, this region, which is potentially the center of gravity of global energy supply, has indeed become the subject of renewed attention with regard to energy security.

Slide 2

Ali Aissaoui - APICORP 13th IEF - Kuwait Slide 2

Outline of presentation

• Major shifts in global energy demand growth patterns

• Energy investment needed to balance supply-demand

• IEA’s MENA upstream ‘Deferred Investment Case’

• Summing up and implications for policy and planning

2. This more topical perspective will be developed along four lines:

First I’ll highlight the major shifts in world’s energy demand and supply growth patterns;

Second, I’ll review the energy supply investment needed to meet global demand;

Third I’ll look critically at the IEA’s ‘Deferred Investment Case’ of MENA upstream and its consequential impact on global oil and gas;

Finally, I’ll sum up the assessment of the context and investment framework and suggest some implications for policy and planning.

Before that, however, I need to decide on the most appropriate long‐term projection from the many made available to us.

Slide 3

What makes current projections compelling and what differentiates them?

• Broad scope and strategic focus

• Varying long-term horizons

• Nuanced thematic emphases

– Energy diversification

– Energy efficiency

– Energy poverty

– Environmental impacts

• But few explicitly derive

investment


BP 2030

SHELL 2050XOM 2040IEA 2035

OPEC 2035EIA 2035

3. We are fortunate to work in an industry that takes a long term view of the challenges facing it. This is well reflected in the projections it regularly publishes. But what make these projections compelling and what differentiates them? They are all broad in scope and strategic in focus, with OPEC, understandably, more concerned about the future of oil. They have very long‐term but varying time horizons, ranging from 2030 for BP to 2050 for Shell. Furthermore, though they differ in nuance and emphasis, they all convey authority to the common goals we are collectively working to achieve, ie:

Expanding and diversifying energy supplies

Improving energy efficiency

Addressing energy poverty

And mitigating the environmental impacts of energy exploitation

Regrettably, not all forecast providers divulge the investment implications of their projections. This is particularly the case of the major oil companies which have traditionally refrained from discussing key elements of their investment and business strategies.

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Slide 4

Only the policy-advisory Institutions consider explicitly investment though to varying degrees

• The US-EIA (quali tat ive ly)

and OPEC (quantitatively for

oil) base their investment on

current policies

• In contrast, the IEA base its

investment projections on a

central scenario: the ‘New

Policies Scenario’


Source: APICORP Research Compilation

0

1

2

3

4

5

6

7

IEA(450 Scenario)

IEA(New Policies

Scenario)

IEA(Current Policies

Scenario)

US-EIA(Reference

Case)

OPEC(Reference

Case)

Billion toe

IEA's Central Scenario

51%49% 49%

21%

39%

Gloabl Energy Demand Growth in Business As Ussual

4. Therefore we are left with the Policy Advisory Institutions as the only ones that explicitly consider investment, though to contrasting degrees. Basically, the US Energy Information Administration (EIA) addresses investment only qualitatively. The Organization of the Petroleum Exporting Countries (OPEC) delves quantitatively into investment but for oil only. While the International Energy Agency (IEA) evaluates investment requirements for the whole energy supply chain both qualitatively and quantitatively. A further difference is that the EIA and OPEC base their views of investment on current policies and dynamics. In contrast, the IEA bases its investment on a ‘New Policies Scenario’ that takes account of announced policy commitments and plans. To the extent that medium term polices shape investment for the longer term, the IEA approach tends to magnify uncertainty further in the future. However, its central scenario and the corresponding investment outlook remains the most suitable reference for our purpose.

Slide 5


Underlying all projections is a major shift in geographical energy demand patterns…

• Driven primarily by population and

economic expansion, global energy

demand increases by 39% to 2035

• This central-scenario growth is

accompanied by a major shift in

the geographical pattern

• Non-OECD responsible for 90% of

the increment, with China and India

alone accounting for half the total Source: IEA World Energy Outlook 2011

(adapted from original)

0

1000

2000

3000

4000

5000

2010 2015 2020 2025 2030 2035

Mto

e China

India

Rest of world

OECD

5. Before proceeding further on investment let me summarize the major findings of these projections. Driven primarily by population and economic expansion, global energy demand increases by 39% to 2035. This growth is accompanied by a major shift in the geographical pattern. As shown in this figure [Slide 5], non‐OECD countries are responsible for 90% of the growth, with China and India alone accounting for half the total increase.

Slide 6

… and significant changes in the sources of energy


• Still driven by transport, oil is to

remain the primary source of

energy for the world economy

• Natural gas nearly catches up with

coal as it ultimately wins in the

competition for power generation

• MENA is expected to supply the

bulk of growth in oil and a

substantial amount of natural gasSource: IEA (adapted)

0

1000

2000

3000

4000

5000

Oil Coal Gas Renewables Nuclear

Mto

e

MENA Contribution to oil and gas growth to 2035104 mb/d

6. Furthermore, while world demand grows for all energy sources, the share of oil and natural gas in global primary energy demand falls from 55% in 2010 to 51% in 2035. Oil, which continues to be driven by transport, is the slowest‐growing form. It is, however, expected to remain the primary source of energy for the world economy. Natural gas nearly catches up with coal as it ultimately wins in the competition for power generation. As a result, global gas demand increases by a rate three times higher than that of oil. With the pattern of energy supply changing accordingly, MENA is expected to supply the bulk of the growth in oil output to 2035 and a substantial amount of natural gas.

Slide 7

The energy investment needed to balance global supply and demand grows to $38 trillion dollars


• Cumulative investment amount to

$37.9 trillion (2010 dollars)

– Oil supply: $10.0 trillion

– Gas supply: $9.5 trillion

– Coal supply: $1.2 trillion

– Biofuel supply: $0.4 trillion

• The highest share is that of the

power sector: $16.9 trillion

Source: IEA (adapted)

26%

25% 3%1%

45%

Total investment: $37.9 trillion

Natural gas

Power(generation, transmission

and distribution)

Coal

Biofuel

Oil

7. Based on these projections, the IEA has established that the investment needed to balance global energy supply and demand over the next 25 years amounts to $37.9 trillion (in dollars of the year 2010). As shown in this figure [Slide 7], Oil supply accounts for $10 trillion, representing 26% of total. Natural gas accounts for $9.5 trillion, representing 25% of total. Coal accounts for $1.2 trillion, representing 3% of total. Biofuel accounts for $0.4 trillion, representing 1% of total. The highest share is that of the power sector, which includes electricity generation, transmission and distribution systems. This sector accounts for $16.9 trillion representing 45% of global energy supply investment.



Slide 8

Cost inflation is the most important factor driving the increase in energy investment


• According to the IEA, costs have

doubled during the last decade, due

to increase in the cost of material,

personnel, equipment and services

• Our interpretation lies in the

concurrent inflation of the main cost

components of EPC:

– cost of input factors

– contractors’ margins

– project risk premiums

– cost of ‘excessive largeness’ Source: IEA World Energy Outlook 2011

8. Cost inflation is the most important factor driving the increase in energy investment. All Policy Advisory Institutions have established that the costs of energy projects have at least doubled during the last decade or so, largely due to rising cost of input factors. Furthermore, as shown in the IEA’s figure [Slide 8], costs in the upstream sector have been found to correlate closely to both oil prices and the levels of exploration and development activities. These trends are consistent with our own findings. In the context of MENA we, in APICORP, have established that the cost of an “average energy project” has more than doubled since 2003. However, our focus has been on the main cost components of EPC contracts. In addition to the cost of input factors, these include contractors’ margins, project risk premiums and the cost of what we have dubbed ‘excessive largeness’. The latter stems from the documented fact that large‐scale projects tend to incur significant delays and cost overruns. Energy project costs would have certainly tripled during the last decade or so, if not for the dampening effect of the global financial crisis. The likelihood is that costs will continue rising.

Slide 9

In the context of ongoing turmoil, the impact of a MENA ‘Deferred Investment Case’ is most relevant

Ali Aissaoui - APICORP Slide 913th IEF - Kuwait

• According to the IEA, MENA is

potentially expected to invest $2.7

trillion upstream through to 2035

• But in the medium term such an

investment may be delayed due to:

− Deteriorating investment climate

− Renegotiations of contracts

− Prudent/conservative policies

− Tougher economic sanctions

− Damage to infrastructure (conflict)

− Constraints on financing Source: IEA, Ibid.

9. In the context of ongoing turmoil in parts of MENA, the IEA pertinently takes a further look at the impact of a ‘Deferred Investment Case’, focusing on the upstream sector. The IEA reasonable, but still arguable, assumption is that upstream

investment is reduced by one‐third across MENA.1 MENA is normally expected to invest $2.7 trillion upstream through to 2035 out of $3.9 trillion of total energy investment. However, investment in the medium term, which stems from a bottom‐up approach, may not be forthcoming. The likely causes for delay, as we interpret them, include the following:

A deteriorating business climate and higher perceived risks;

Potential renegotiations of agreements in the wake of changing regime circumstances;

Prudent or conservative oil and gas depletion policies;

Tougher economic sanctions on the region’s biggest holder of combined oil and gas reserves;

And in case of conflict, durable loss of production due to serious damage to infrastructure;

Last but far from least, is a serious constraint on financing.

Slide 10

Our MENA energy capital structure highlights specific funding constraints


UpstreamC: $152bnL: 0:100 Aggregate

capital required and

capital structureC: 525bnL: 43:57

Retained earnings

APICORP Research

Medium and long term loans

Bonds or sukuks

Common stocks

State budget

allocationDownstream

C: $220bn

L: 60:40

MidstreamC: $27bnL: 0:100

Power GenerationC: $126bnL: 70:30

F I N A N C I N G(Conceptual)

Internal sources

Capital required

External sources

Re su lt in g cap i ta l st r u ct ure

[ L : Deb t :Equ i t y ]

I N V E S T I N G(empirical)

Depends worryingly on oil and

related gas prices

Adequate as long as oil prices

remain above $100/bbl

Negligible contribution of domestic

capital markets

Collapsing loan markets in the

wake of the Eurozone debt crisis

Source: APICORP Research - MENA Energy Investment Outlook 2012-2016

Inte

rnal

fin

anci

ngE

xter

nal

finan

cing

10. I wish I could have more time to delve deeper into the financing constraint. Let me just say that financing, which is at the heart of corporate investment strategic decisions, is a key part of the planning process. Financing is basically determined by the structure of capital requirement, which we have established to be 43% debt and 57% equity for MENA oil and gas as a whole. Debt, which is dominant in the downstream sector, is sourced externally. With still limited opportunities for raising funds from the capital markets, both domestic and international, debt is typically provided through the syndicated loan market. Unfortunately, this market has collapsed in the wake of the Eurozone debt crisis, as most European banks have pulled out of the region. In contrast, equity, which is a dominant part of the upstream sector, is generally financed internally through retained earnings and state budget allocations. Therefore, equity could only be secured if oil prices remain above $100/bbl, which corresponds to the current estimated average fiscal break‐even price within the OPEC area. As hinted by Schlumberger’s Chairman in a recent talk to Barclays Capital Commodities Conference ([New York, 1

st March 2012], $100/bbl

1 For further interpretation of the IEA’s DIC, see Ali Aissaoui “IEA’s World Energy Outlook: Review and Discussion of MENA Deferred Investment Case”, MEES dated 20 February 2012.



may also constitute the break‐even price for developing frontier oil.2 This was only $75/bbl less than two years ago!

Slide 11

The IEA’s DIC has many impacts, mostly underpinned by soaring oil and gas prices


• Oil price increases to

$150/barrel ($175 nominal),

before converging towards the

IEA’s central scenario

• More complex to analyze and

predict, gas prices also expected

to increase, though not to the

same extent as oilSource: IEA World Energy Outlook 2011

0

20

40

60

80

100

120

140

160

2005 2010 2015 2020 2025 2030 2035

$/ba

rrel

($20

10)

Deferred Investment Case

New Policies Scenario

11. Getting back to the IEA’s investment outlook, MENA ‘Differed Investment Case’ has many impacts, including on supply, demand and the terms of energy trade. Obviously, underpinning most of these impacts are soaring oil prices. Indeed, under this case, oil prices are projected to increase to $150/barrel in real term (i.e. $175 nominal) by 2016, before progressively converging towards the central scenario’s assumption. This trend appears already below current price levels. Gas prices are more complex to predict as their analysis has to factor in highly uncertain regional pricing differentials due to rapidly changing market structures. Nonetheless, gas prices are also expected to increase, though not to the same extent as oil prices.

Slide 12


Summing up the context and investment assessment

• Amid major shifts in demand and supply patterns, MENA is to

provide the bulk of oil output growth, and a large amount of gas

• This involves upstream investment of over $100bn per year through

to 2035 in the IEA’s central scenario

• It is far from certain that such magnified levels will be forthcoming

– In the medium term, the causes for delay are all likely when not

already a reality

– In the longer term, MENA’s core producers are treated as

passive residual suppliers

12. With this pressing concern in mind, it is time to sum up and conclude our assessment of the context and investment framework for MENA. Amid major shifts in the patterns of global demand and supply, the region is expected to provide the bulk of oil output growth, and a large amount of natural gas.

2 In clarifying this point, Andre Gould expressed the opinion that “the alternative source of new non‐Middle East oil production in the short term is deep‐water offshore, the marginal barrel [of which] cannot be far from $100” (excerpt from an email to the author).

This involves upstream investment of over $100bn per year through to 2035 in the IEA’s central scenario. It is far from certain that such inflated levels of investment will be forthcoming. In the medium term, which takes a bottom‐up approach, the causes for delay are all likely when not already a reality. In this context, continuing global demand growth ought to have dramatic impacts on prices. In the longer term, which takes a top‐down approach, MENA and its core producers are treated as passive residual suppliers with little regard to their policy objectives and constraints

Slide 13


The implications for policy and planning can be wide-ranging and far-reaching

• In the medium term:

– Assuming no demand destruction, more spare capacity need to

be available

– But how that can be planned in face of lead-time investment

uncertainty?

• In the longer term:

– Fiscal conditions permitting, very prudent and conservative

depletion policies will likely continue

– Unless a new paradigm of cooperation addresses the challenges

of economic diversification

13. The implications for policy and planning are wide‐ranging and far‐reaching. The ones we would like to suggest can be summarized as follow. In the medium term, assuming no demand destruction, more spare capacity need to be available to cushion anticipated oil supply shortages and avoid further price upsurge. To be sure, Saudi Arabia remains committed to providing a major portion of that capacity. But how that can be planned in face of lead‐time investment uncertainty in other MENA producing countries with significant upside production potential? In the longer term, fiscal conditions permitting, very prudent depletion policies will likely continue as long as economic diversification is not enough to succeed. In such a case, can a new paradigm of cooperation be established to better address producers’ socio‐economic expectations and allay their post‐oil anxiety?

Structure of 13th International Energy Forum(Kuwait, 12‐14 March 2012)

The 13th International Energy Forum (IEF13) was structured around four sessions to cover issues most relevant to today’s energy producer‐consumer dialogue:

Session 1: Meeting Future Energy Demand: Planning and Investment for the Long‐term;

Session 2: Energy Markets: Mitigating Volatility;

Session 3: Achieving Environmental and Social Sustainability: Lower Emissions and Access for All;

Session 4: The Global Energy Dialogue: Charting the Future of Energy Cooperation.

The program, conclusions and recommendations of both IEF13 and the concomitant 5th International Energy Business Forum (IEBF5) should be available on www.ief.org

Economic Commentary

Vol 7 No 4-5, April-May 2012


MENA Power Reassessed: Growth Potential, Investment and Policy Challenges This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 30 April 2012. The views expressed are those of the author only. Comments and feedback may be sent to <aaissaoui@apicorp‐arabia.com>.

1. Since the onset of the global financial crisis in 2007, energy investment growth in the Middle East and North Africa (MENA) has seriously contracted.1 As the ‘ option to wait’ was becoming more valuable for some investors, we advocated the exclusion of enabling energy infrastructure such as power from any such option. Long‐standing underinvestment in this sector has caused shortfalls in electricity supply and led to serious economic bottlenecks and social frustrations. Ongoing turmoil in parts of the region has somewhat vindicated our stance. Power may indeed emerge as a critical sector featuring prominently on top of governments’ policy agendas. Catching up large unmet potential demand needs massive investment, which cannot be achieved without addressing broader policy challenges.

2. This commentary discusses the growth potential of MENA power sector, the investment requirements and the challenges involved. Contrary to previous analyses, which focused on the generation link of the electricity value chain, investment is extended to the transmission and distribution (T&D) systems. The commentary is in three parts. The first provides a descriptive overview of the growth pattern and performance of MENA power generation. The second assesses the potential for capacity growth and the resulting capital investment in new power plants as well as in T&D for the five‐year period 2013‐17. The third discusses the major challenges associated with implementing policies and programs.

Growth Pattern and Performance

3. In a move to improve efficiency and lessen funding constraints, the power industry has undergone significant institutional and regulatory changes in many MENA countries during the last decade or so. However, despite governments being able to shift part of the burden of developing and financing projects to the private sector, the industry has continued to struggle to keep pace with fast‐growing demand. Electricity demand and the resulting generation capacity and production have been driven by rapid population growth and greater urbanization, sustained economic and industrial development, and heavily subsidized electricity tariffs for consumers. This is not to mention the changing characteristics of the electricity demand profile – in particular its summer peak – which, in a context of hotter climate, has increasingly been shaped by air conditioning load.

1 MENA is here defined to include the Arab world and Iran. Power generation in Sudan is kept inconsequentially aggregated. Within MENA the GCC clusters Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, and the UAE.

4. These drivers cannot easily be captured in a succinct overview. However, Figure 1 provides some insight into the growth pattern of the region’s power sector based on the evolution of key indices. It shows that over the last three decades, staring from the common base year of 1980 (index 100), capacity and production have consistently grown more rapidly than GDP, actually much more during the last decade or so. Furthermore, during the 1980s, then later in the 2000s, capacity and production grew in close parallel with each other. Meanwhile, however, in the 1990s and early 2000s, production grew faster than capacity as excess capacity inherited from past periods of high infrastructure investment had to be absorbed. However, this trend analysis is not enough to evaluate the performance of the power system.

Figure 1: Evolution Of MENA GDP, Capacity and Production

0

200

400

600

800

1,000

1980

1985

1990

1995

2000

2005

2010

Index ‐Base year 1980=100

MENA Poduction Index

MENA Capacity Index

MENA Constant GDP Index

APICORP Research using data from DoE‐EIA, AUPTDE and IMF (for GDP)

5. Before delving more specifically on performance, it might be useful to briefly examine the patterns of growth at the country level. Fully available data for 2010 indicate that 11 countries (out of 23), whose installed capacity is higher than 5 GW, generated a little more than 90% of total output. Among them, the six countries of the Gulf Cooperation Council (GCC) accounted for 43% of MENA total and 54% of the Arab world.

2

We should expect country differences to reflect different demographic and economic levels and structures, as well as contrasting climate conditions. A 2010 cross‐section regression analysis highlights these differences. As shown in Figure 2, on a log transformed basis per capita capacity increases with per capita GDP in a nearly linear pattern. This stems from the fact that GDP per capita is a proxy for domestic factors that are strong determinants of electricity demand in the region. Accordingly, the GCC countries have ended in the high‐end tier.

2 Detailed statistics for 2010 include those provided by the Arab Union of Producers, Transporters and Distributors of Electricity (www.auptde.org) as well as the US Energy Information Administration (www.eia.gov).

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Figure 2: MENA Power and GDP – A Cross‐Country Snapshot

1.0

1.5

2.0

2.5

3.0

3.5

4.0

3.0 3.5 4.0 4.5 5.0

Log per‐cap Capacity

Log per‐cap GDP

APICORP Research ‐ 2010 data

Algeria

Libya

QatarSaudi Arabia

UAEBahrain Kuwait

OmanGCCNon‐GCC MENA

Lebanon

Sudan

Mauritania

Yemen

IraqJordan

SyriaEgypt

Morocco

IranTunisia

6. As for the performance of MENA power generation (19 countries with available data), it can more adequately be assessed on the basis of two key indicators: capacity factor and load factor. Because of the demand profile (peak load and seasonal variations) and the inability to store electricity, generators need to maintain a substantial back up reserve, which bears on the efficiency of the power system and its economic performance.

7. The first performance indicator is a measure of capacity utilization. Capacity factor has improved from about 40% in the 1980s and early 1990s to a little more than 50% currently. In 2010 it was the highest in Syria with 63% and the lowest in Morocco with 41%. Contrary to Syria, where generators have had to struggle to compensate for lagging capacity, in Morocco alternative supply in the form of import was available. Indeed, with soaring oil prices Morocco’s better option was to substitute up to 20% of its thermal generation capacity with lower cost electricity from Algeria and to a much larger extent from Spain, through existing interconnections. In any case, capacity factor should be interpreted with caution since, at the high ambient temperatures prevailing in most of the region, actual capacity is lower than nameplate capaciy.

3

8. The second performance indicator is defined as the ratio of average load to peak load. Load factor can be interpreted in two opposing ways. On the one hand, a too low ratio may indicate an inefficient power system. On the other hand a too high ratio may signal that the system is stretched to its capacity limit and could collapse should peak demand be higher than anticipated. Load factors within MENA range from 56% in Qatar to 71% in Algeria, indicating sound systems overall but with lesser efficiencies in countries at the lower end of the scale. In addition to Qatar, these include Bahrain, Morocco and Tunisia.

Investment Outlook

9. Due to the technical and specialized nature of the economics of power supply, the determination of investment

3 Nameplate capacity is determined at 15°C, which is far below prevailing temperatures in most MENA countries.

involves sophisticated tools far beyond the analytical scope of this commentary. Instead, the intention is to provide a broad estimate of the level of investment required so as to develop a good understanding of the challenges ahead. Our estimates are based on a simple but duly qualified analysis of past trends. Extrapolating the average ratio of capacity growth to GDP growth observed in recent years of about 1.45 may lead us to accept that, under an assumption of GDP growing at 4.5%, future capacity would increase at an annual rate of about 6.5%. However, factoring in unmet potential demand for electricity may warrant higher rates. Similarly, an incorrect interpretation of the cross‐section shown in Figure 2 can lead us to believe that the top ranking GCC countries are near saturation point. But this may not be the case if we consider that Saudi Arabia, by far the biggest social and economic state, is still in a lift‐off phase, not to mention the much higher potential for growth in the other MENA lagging countries. To be sure, future growth may take a more efficient and less intensive path. But this depends on promoting demand‐side management (DSM) and eliminating electricity tariff subsidies, both of which will be hard to achieve in the medium term.

10. Based on these considerations, medium term capacity growth, which has been worked out on a country by country basis, is expected to be much higher than that of economic output: 7.8% for the period 2013‐17 against 4.5% for GDP. As detailed next, this would require an investment in MENA power sector of about $250bn, 59% for new generation capacity and the remaining 41% for T&D.

11. The growth rate of 7.8% translates into a five‐year capacity increment of 124 GW above the 2012 level, partly through combined power/water desalination plants. Therefore, with current reference costs – reflecting prevailing prices of engineering, procurement and construction (EPC) and country investment climates – the resulting capital requirements will be in the order of $148bn for the forecast period. As shown in Table 1, the GCC area, which will continue to grow at the highest rate, accounts for 43% of MENA total and 53% of the Arab world total (expenditures for nuclear power generation is implicit in the case of Iran and the UAE).

4

Table 1: MENA Power Capacity and Investment, 2013‐17

2011* installed capacity (GW)

2011* electricity production (TWh)


growth (%)

2013‐17 capacity addition (GW)

2013‐17 capital

requirements (G$)

Maghreb 1 32.0 112.8 7.4 14.6 17.6 Mashreq 2 60.7 294.1 7.6 29.1 36.8 GCC 3 104.8 461.6 8.5 57.0 63.1 Rest of Arab world 4 4.4 15.6 6.6 1.8 2.3 Iran 49.7 227.0 7.0 21.4 27.8

MENA Total 251.6 1111.1 7.8 123.9 147.6 * 2011: estimates1Maghreb: 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 Rest of Arab world includes Sudan and Yemen, but excludes Comoros, Djibouti and Somalia for lack of data.

Compilations and projections by APICORP Research

4 In Iran, while Bushehr I was officially inaugurated in 2010 (but operated a year later), there is no plan to complete Bushehr II. In Abu Dhabi the first such a plant is not expected before 2017.

Economic Commentary



12. As for investment in T&D, it derives from the need to develop adequate transmission networks to supply electricity to industries, businesses and households. These networks are differentiated between transmission and distribution grids. The former consist of high voltage lines designed to transfer bulk power from generation plants to large industrial customers and distribution centers, generally over long distances. In contrast, the function of low voltage distribution grids is to supply power to final consumers in urban and, whenever socio‐economically desirable, in rural areas as well.

13. Under this grid‐based supply perspective,5 the determinants of T&D investment vary from country to country, depending on the size and location of generation capacity, distances to end users, the extent of development and density of urban areas, as well as built‐in redundancy in the transmission system to ensure reliability. According to the IEA World Energy Outlook 2011, worldwide T&D infrastructure accounts for 42% of all power sector investment, with significant regional variations for transmission and distribution respectively. A simple transposition of relevant regional ratios to respectively the Maghreb, Mashreq, the GCC and Iran, results in MENA T&D investment of $103bn for the period 2013‐17, with further breakdown given in Table 2.

Table 2: Total Investment in MENA Power Sector, 2013‐17

Investment in $bn Generation (G)

Transmission (T)

Distribution (D)

Total (T,D)

Total (G, T, D)

Maghreb 1 17.6 3.9 9.7 13.6 31.2

Mashreq 2 36.8 6.3 18.0 24.3 61.1

GCC 3 63.1 10.7 30.9 41.6 104.7

Rest of Arab world 4 2.3 0.5 1.3 1.8 4.1

Iran 27.8 6.1 15.3 21.4 49.2

MENA Total 147.6 27.5 75.2 102.7 250.3

Major challenges

14. Investment on this scale will not occur without addressing current challenges, prominent among which are fuel and funding. These challenges, which are considered far beyond the scope and resources of any public utility or private developer, are discussed next in turn.

15. Electricity can be generated by different technologies using a variety of fuels. Reflecting the region’s endowment in hydrocarbon resources, MENA power sector relies heavily on thermal plants fueled essentially from natural gas and oil products. In 2010, about 60% (57% in the Arab world) of output was generated using natural gas and 37% (41% in the Arab world) using oil products. The remaining 3% (2% in the Arab world) was from hydro and smaller amounts of imported coal, not to mention the still immaterial contribution of nuclear, solar and wind power (Figure 3).6

5 Off‐grid supply may be more relevant for rural and remote areas. 6 The figures for 2010 do not include electricity generated from Bushehr plant, which has been adding electricity to the national grid since September 2011 only.

Figure 3: MENA Electricity Generation by Fuels

0

20

40

60

80

100

Qatar

Tunisia

Algeria

UAE

Oman

Iran

Egypt

Jordan

Syria

Bahrain

Libya

Iraq

Saudi Arabia

Kuwait

Yemen

Sudan

Morocco

Lebanon

Mauritania

% share

Natural gas Oil products Hydro and others

APICORP Research

16. The fact that the power generation sector is the single most important industrial user of natural gas in key countries in the region, raises the extent proven reserves can meet long‐term fuel demand. Indeed, although most MENA countries are endowed with substantial gas reserves, supply sustainability should not be taken for granted. To gauge each country’s supply circumstances from publically available data, we have developed specific metrics. Although a clear‐cut supply picture is not easy to draw, we have found that the trend towards an optimal supply threshold (OST) is a fairly good measure of gas supply sustainability. Reflecting the structure and use of hydrocarbon reserves (crude oil, natural gas and NGLs), OST is defined as the one set of solutions that equalizes the share of natural gas production in total hydrocarbon production with that of natural gas reserves in total hydrocarbon reserves. A simple Euclidean distance, expressed in percent, shows how far or how near different countries are from that threshold.

17. This is illustrated by the 2010 cross section in Figure 4. 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 Kuwait, Saudi Arabia, Libya, the UAE, and Iraq, whose distances to OST are lower than 5%. Therefore, each of these countries now runs the risk of not being able to keep its position once there. Already this is the case of Bahrain, whose negative distance suggests that it is using more gas than it could possibly afford.

7 In any case, switching to higher‐value oil products entails an opportunity cost of foregone export revenues.

7 For a thorough analysis of the pattern of natural gas supply in the region, see A Aissaoui, ‘MENA Natural Gas: A Paradox of Scarcity Amidst Plenty’ (MEES, 27 December 2010).

Economic Commentary



Figure 4: Distance to Optimal Gas Supply Threshold (OST)

‐10% ‐5% 0% 5% 10% 15% 20% 25%

Yemen

Qatar

Algeria

Iran

Syria

Oman

Egypt

Tunisia

Iraq

UAE

Libya

Saudi Arabia

Kuwait

Bahrain

Distance to OST < 0%

Distance to OST within [0,5%]

Distance to OST >5%

APICORP Research

18. As for funding constraints, they should be considered in the context of the restructuring and liberalization that has been taking place in the region. While these reforms have key features in common, they differ somewhat in terms of institutional design and application. The common tendency, however, is towards a phased approach to competitive markets, allowing first private participation in power generation while governments continue to hold some monopoly over transmission and distribution. In this context, the prevailing model is the so‐called ‘single buyer’, whereby the incumbent public utility procures power from independent power and power/water producers. IPPs and IWPPs are typically tendered on a cost‐competitive basis with projects structured to provide them with the option to build, own, operate or transfer.

19. In this context, T&D is likely to continue to be financed from internal sources, ie utilities’ retained earnings and state budget allocations, eventually supplemented by external soft multilateral bank loans. Internal financing could only be secured if the level of electricity tariffs is enough to cover total system costs and generate some profits. As for governments’ involvement, it depends on their fiscal positions and, in the case of the oil and gas producing countries, on oil prices remaining above $100/bbl, which is our current average fiscal break‐even price within the OPEC area.8

20. In contrast to T&D, financing power generation is assumed to be mostly undertaken on a project finance basis, via a non‐recourse structure, whereby equity and debt are paid back from the revenues generated by the project company. With still limited opportunities for raising funds from the capital markets, both domestic and international, debt is typically secured from the region’s syndicated loans market. Unfortunately, this market has been affected by the global financial crisis. More seriously, the resurgence of the Eurozone sovereign debt crisis has led most European banks to pull out from the region. As a consequence and as shown in Figure 5, the annual number of deals in the power and

8 For the original methodology, see A Aissaoui, ‘Fiscal Break‐Even Prices: What More Could They Tell Us About OPEC Policy Behavior?’ (MEES, 14 March 2011).

power/water sector has dwindled from a peak of 17 in 2008 to a bottom of 10 in 2011. Correspondingly, the annual deal value decreased from a record high of $23bn in 2008 to a low of $8bn in 2011. Also, the cost of borrowing as measured by ‘all‐in‐one’ pricing, although coming down from the peak of 302 bps in 2009, remains challenging at 191 bps.

Figure 5: MENA Power: Loans and ‘All‐In‐One’ Pricing

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150

200

250

300

350

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10

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20

25

2000

2001

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Reported deals

All‐in pricing

17 Number of projects

13

15

5

12

10

13

17

37 6

6

APICORP Researchusing Dealogic database

10

21. Even assuming a return of the European banks, IPPs/IWPPs would hardly attract debt financing without lenders satisfied with additional risk mitigation measures. These include higher quality of developers, reduced tenors for long term debt, better allocations of risks in the longer term power purchase agreements between private developers and public utilities and effective hedging of fuel supply risks. Furthermore, while current financing trends are common throughout MENA region, the case of Iran should be assessed based on its specific context. In this country, tougher economic sanctions are expected to deter reforms in the power sector and severely restrict funding.

Conclusions

22. As a result of high population growth, fast expanding urban and industrial sectors, increasing needs for air conditioning, and heavily subsidized electricity tariffs, many countries within MENA have been struggling to meet fast‐growing demand for electricity. With ongoing turmoil, catching up with unmet demand may be perceived as socially and politically more desirable. In the absence of active demand side management, this will entail capital investment of about $250bn for the period 2013‐17, 59% of which in new generation capacity and the remaining 41% in T&D. Investment of this scale will face many challenges, prominent among which are fuel and funding. The first stems from the scarcity of natural gas in key countries in the region and the opportunity cost of generating electricity using high‐value export oil products instead. The second results from the inadequacy of internal and external financing and the reluctance of many MENA governments to support cash‐strapped public utilities, which are committed to continuing to invest should the private sector be not forthcoming. Both fuel and funding challenges involve significant policy dilemmas that need to be addressed quickly and effectively.

Economic Commentary Vol 7 No 6, June 2012


I s the Ant i c ipa ted R i se i n Long ‐ te rm Oi l Pr i ce I nev i tab le?A Not So Simple Framework

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 9 July 2012. The views expressed are those of the author only. Comments and feedback may be sent to <aaissaoui@apicorp‐arabia.com>.

1. Recent research studies conducted by international policy‐advisory institutions have raised the prospect that severely constrained supply growth could drive long term oil prices much higher than previously assumed. The International Energy Agency (IEA) for instance has found that, with lingering socio‐political turmoil in the Middle East and North Africa (MENA), a shortfall in investment in the upstream sector could shift output to higher cost sources resulting in real oil price peaking to $150 per barrel within the next five years.1 Other institutions have reported similar trends even assuming that higher oil prices would spur further technological innovation that might improve supply. This is the case of the IMF whose research staff has empirically evaluated a model of the world oil market, which encompasses both the geological view (resource constraints determining future output and prices) and the technological view (higher prices encouraging technological solutions), to forecast a permanent doubling of real oil prices to $200 per barrel within 10 years.

2

2. To the extent that long term prices are set by perceptions about the price level required to motivate investment and bring long term demand and supply into balance, the above expectations should have been reflected in the shape of the forward oil price curve. However, at the time of writing, the back‐end of the curve – the proxy for long term price – has remained stubbornly below $100 per barrel (Brent five‐year forward and beyond). In this commentary we consider both the forward curve and the future supply curve, in order to gain the insight needed to explore whether or not the prospect of a large price swing to the upside is inevitable.

The Forward Curve

3. To better explain commodity price behavior, leading research analysts have provided a useful framework by postulating, in the words of Jeffrey Currie and his colleagues at Goldman Sachs, that “on balance, the key to commodity price movements is marginal costs and inventories”.

3 Hence, the forward curve is decomposed into a short term, cyclical component and a long term, structural component. The cyclical element is driven by fluctuations in fundamentals, as ultimately captured by inventory levels. The structural element is determined by the cost of bringing the last needed unit of the commodity output to the market. Central to the framework is that the structural element provides an anchor and a hinge around which short term prices fluctuate (Figure 1). The dynamic of commodity prices can be observed in the changing shape of the forward curve. In a tight market a premium for prompt delivery shifts the curve into backwardation. Conversely, in a soft market a discount, to offset the costs of carrying inventories forward, shifts the curve into contango.

1 IEA, World Energy Outlook 2011. 2 Jaromir Benes et al., “The Future of Oil: Geology versus Technology”, IMF, WP/12/109, May 2012. 3 Jeffrey Currie et al., “Commodity Prices and Volatility: Old Answers to New Questions”, Goldman Sachs, Global Economics Paper No. 194, March 30, 2010.

Figure 1: Decomposition of a Commodity Forward Curve

$/barrel

In a cyclically tight market the spread is typicallypositive, reflecting a premium for prompt delivery

In a cyclically soft market the spread is negative, reflecting the cost of carrying inventory

Price = MC + d, where d is a delivery premiumIn a tight market or a discount in a soft market

The long‐dated, structuralcomponent of price

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40

20

100

120

140

1 2 3 4 5 6

= d

The short‐term, cyclicalcomponent of price

= MC

Years to expiry

Backwardation

Contango

Source: Goldman Sachs Global ECS Research

4. While this framework seems conceptually intuitive and robust, the suggestion that the marginal cost is a primary determinant of long dated commodity price has been challenged when it comes to oil. For instance, Paul Horsnell, from Barclays Commodities Research, argues that “one could try to say that long term prices should be determined by marginal costs”, but “the link between costs and prices has tended to be very weak to non‐existent in oil, particularly given the operation of the low cost producers at the margin of the market”.

4 However, as elaborated later, Dr Horsnell’s argument can be addressed by substituting for marginal cost the average unit cost of the most expensive project’s output.

5. Equally worth pondering is the case made by Frédéric Lasserre ‐ former Global Head of Commodities Research at Société Générale ‐ who observes that the forward curve can be over‐priced, ie long‐dated price can be higher than marginal cost. The reason he gives is that the above characterization is incomplete and has to factor in the demand side. Goldman Sachs research staff have highlighted that in an environment of anemic long term supply growth, long‐dated price needs to rise above marginal cost in order to achieve demand destruction and bring supply and demand into balance. Mr Lasserre’s suggestion to “fine‐tune the model by assuming that the marginal cost acts as a floor to the back [of the forward curve] while the price [that triggers] demand destruction acts as a cap” is particularly relevant.

5

6. Having clarified the relationship between marginal cost and long term price, the key question we now seek to address is why is it that the price expectations of the IEA and the IMF are not reflected at the back end of the forward curve (Figure 2)? To provide an answer to the question, we need to bring into the discussion the long term oil supply curve as well.

Figure 2: Brent Forward Curve – 2012 Trading Range

Years to expiry

$/barr

el

Source: Barclays, Commodities Research

4 Paul Horsnell, “The Dynamics of Oil Price Determination”, Oxford Energy Forum, Issue 71, November 2007. 5 Email exchange with the author dated July 2, 2012.

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Economic Commentary Vol 7 No 6, June 2012


The Supply Curve

7. A great deal of insight into the marginal cost of production, and therefore long term price, can be derived from a long term supply curve. As shown in Figure 3, a reasonable approximation to such a curve is obtained by ranking current and potential sources of supply, from lowest to higher cost. The cost in Saudi Arabia is put at $25 per barrel. Within other MENA countries it is estimated at $35 per barrel. The cost of non‐MENA conventional oil production may be as high as $45 per barrel. Estimates for more expensive unconventional oil production range from $50 per barrel for CO2 based enhanced oil recovery (EOR) projects to $100 per barrel for gas‐to‐liquids (GTL) and coal‐to‐liquids (CTL) projects. The conjectural supply distribution in Figure 3 implies that to balance future global demand a hypothetical total output of 100mn barrels of oil is produced each day at an assumed marginal cost of production of $100 per barrel.

Figure 3: Juxtaposing the Forward Curve and the Supply Curve (This figure is provided for illustration purposes only)

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Saudi Aabia

Other MENA

Otherconventional

EOR‐CO2

Deep water

Heavy oil/Bitumen

Oil sands/Shale oil

GTLs/CTLs/Biofuels

$/barre

l

Cumulative production ~ 100 mb/d Source: APICORP Research

8. As suggested by Frédéric Lasserre, a simple juxtaposition of the supply curve and the forward curve (Figure 3), can perfectly illustrate how long‐dated price moves in tandem with the marginal cost of supply.

6 For a given demand, we should expect constraints on low cost oil supply to shift output towards high cost oil. As a result, the price at the back end of the forward curve should adjust to stimulate investment and deploy new capacity. But as argued next, cost and therefore price would probably not need to increase to that effect.

Non‐inevitability of Price Rise

9. Having illustrated how long‐dated oil price may move in tandem with the marginal cost of production, our focus now is to try and infer from such a cost the direction of a long term price.

10. Marginal cost is essentially unobservable. However, as we suggested earlier, it can fairly easily proxied by the average unit cost of the most expensive project’s output. Accordingly, and in the case of a planned greenfield upstream project, it includes the costs of finding, developing and lifting, plus fees, royalties and taxes as well as a return commensurate with investment and risk. What is much harder is to predict it. The difficulty stems from the fact that, as depicted in the triadic T‐P‐E of Figure 4, costs lie at the confluence of uncertain technological, political and economic factors.

6 Frédéric Lasserre, “What are the key drivers for oil prices”, PPT Presentation to IFRI Energy Breakfast Roundtable, Brussels, December 20, 2007.

Figure 4: Costs at the Confluence of the T‐P‐E Triadic

Technologyand innovation

Politicsand policy

Economicsand project cost

inflation

Source: APICORP Research

11. First, finding and developing oil depends on technology and innovation, which should continue enabling frontier oil to be produced cost‐effectively and productively. In the period from the mid‐1980s to the mid‐1990s, significant technological breakthroughs such as 3D seismic, horizontal drilling and subsea completion, have greatly contributed to the exploitation of new resources particularly in deep waters. In recent years, sub‐surface hydraulic fracturing, combined with horizontal drilling, allowed shale hydrocarbons to be produced more economically. Furthermore, in the particular case of shale oil, new in situ conversion processes, which apply heat to release oil, have proved to be affordable under current economic conditions, though still environmentally challenging.

12. Next, finding and developing oil depends on politics, which is a powerful motivator of policy. In some producing countries such policies have been rather restrictive in terms of either access or taxation. In contrast, motivated by concerns about security of supply, key consuming countries’ policies have generally been more supportive. In these countries, notwithstanding stricter environmental regulations, fiscal incentives and appropriate public and private financing mechanisms have, on balance, greatly contributed to growing investment and output.

13. Finally, cost inflation is a major factor in project economics. The nearly tripling of the cost of energy projects, observed during the last decade or so, has been largely due to rising prices of input factors, contractors’ margins and project risk premiums. Such a trend, however, is unlikely to endure. As the industry continues to experiment with new technologies and innovates with contracting and managing large‐scale projects, we should expect it to shorten the learning curve and reduce costs.

14. To sum up, marginal cost – or to be precise its proxy – can hardly be predicted due to the combined effect of highly uncertain factors. But uncertainty does not justify the anticipation of higher costs. On the contrary, it can lead to the opposite result. In other words, technology, politics and economics can also combine auspiciously to lower marginal cost, therefore lending support to moderate long term oil price.

Conclusions

15. As global oil demand increases, even if only moderately, and production from mature areas declines, finding and developing additional oil will definitely be more challenging in the future. However, the view that marginal cost, which drives long‐dated price at the back of the forward curve, should increase to stimulate additional supply is not immediately plausible. Despite (or because of) all the uncertainties, the likelihood, based not on empirical data but on reasoned judgment, is that rising marginal cost, and therefore long‐dated price, may not be inevitable.

Economic Commentary Volume 7 No 7, July 2012


Global Trends in Renewable Energy Investment: A Review of the Frankfurt School‐UNEP’s Report and Discussion of the MENA Case

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 23 July 2012. The author wishes to state that there is no conflict of interest arising from this review and that the opinions expressed reflect his personal views only. Comments and feedback to aaissaoui@apicorp‐arabia.com

1. In June 2012, the Centre for Climate Change and Sustainable Energy Finance – a collaborating partnership between the United Nations Environment Program (UNEP) and the Frankfurt School of Finance and Management – released its annual Global Trends in Renewable Energy Investment.1 Successive editions of this report have provided an elaborate analysis of relevant trends and issues. This year’s report, which was released just ahead of the Rio+20 Summit,

2 took advantage of the event to broaden exposure and amplify policy messages.

2. The review of the centre’s report is part of our efforts to keep abreast of the structural changes taking place in the energy industry. In so doing, we seek to raise awareness of the challenges and opportunities that lie ahead for the countries of the Middle East and North Africa (MENA).3 The commentary is in three parts. The first presents the report’s concept and institutional oversight. The second summarizes its key findings and messages. The third extends the discussion to trends and policy issues within MENA.

Concept and Institutional Oversight

3. Since it was first launched in 2008, the centre’s report has provided consistent and comprehensive data and analyses of investment and financing of renewable energies worldwide. As with previous editions, this year’s report has been overseen by a five‐member team of editors who bring to the task the expert perspectives of their seconding institutions.

4. Commissioned by UNEP’s Division of Technology, Industry and Economics (DTIE), the report testifies to the qualitative cooperation between UNEP and the Frankfurt School – one of Germany’s leading business schools. It further acknowledges the longstanding contribution of Bloomberg New Energy Finance (BNEF), which acted as lead author and chief editor. This multi‐institutional oversight and the fact that the report is both supported by the Federal Government of Germany and endorsed by the Renewable Energy Policy Network for the 21st Century, all appear to be aiming at weighing on policy making and implementation and moving forward the global sustainable energy agenda.

Key Findings and Messages

5. In addition to an executive summary and a glossary of financial and related terms, the 80‐page report is composed of 10 chapters generously illustrated with graphs and, in a world where seeing is believing, a host of pictures of connected, or readily connectable renewable energy supply systems. The coverage is broad and takes in many areas while emphasizing the evolving contexts. Therefore, our review has been selective, focusing on the patterns of

1 Frankfurt School‐UNEP Centre, Global Trends in Renewable Energy Investment 2012 (fs‐unep‐centre.org). 2 The Rio+20 Summit took place in Brazil on 20‐22 June 2012 to mark the 20th anniversary of the 1992 United Nations Conference on Environment and Development (UNCED) in Rio de Janeiro. 3 As usual in our commentaries, MENA is defined to include the Arab world and Iran.

investment, funding sources, trends in competiveness, government support policies and the likely impediments to investment.

6. The central finding of the report is that in 2011, global new investment in renewable power and fuels (solar, wind, modern biomass, waste‐to‐energy, biofuels, small hydro, geothermal and marine) increased by 17% to reach an all‐time high of $257bn. This was more than six times the amount achieved in 2004 and nearly the double of 2007 – the year preceding the global financial crisis. As shown in Figure 1, despite the crisis and the ensuing recession investment growth has been fairly resilient.

Figure 1: Global New Renewable Investment ($bn)

39

61

97

133

167 161

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257

2004 2005 2006 2007 2008 2009 2010 2011

Corporate R&D

Government R&D

VC/PE

Public markets

Small distributed capacity

Asset finance *

*Asset finance volume adjusts for re‐invested equity. Total values include estimates for undisclosed deals. Source: Bloomberg New Energy Finance, UNEP

7. As a matter of fact, actual investment in renewable energy amounts to $325bn when adding $68bn worth of merger and acquisition transactions in 2011. Otherwise, and as detailed in Figure 1, 91% of financial instruments went towards the funding of generating capacity and equipment (asset finance and small distributed capacity). The remaining 9% were roughly split between technology development (venture capital and R&D by both governments and corporates) and equipment manufacturing (private equity expansion capital and public equity markets).

8. The regional pattern of investment appears markedly uneven, with two thirds of investment originated in developed economies and one third in the developing ones (Figure 2). Despite a decline of investment in Germany – the world’s third biggest market after China and the US – Europe remained by far the most important investment area. It was followed by China and the US, with the latter closing in on the former. The lowest level of investment is found in MENA (actually the Middle East and Africa in Figure 2). For reasons developed more fully further below when discussing the MENA case, this poor performance has more to do with policy uncertainty than it does with business motivations.

Figure 2: Regional Pattern of Investment

7.4 11.2

27.2 28.537.7

22.532.5

50.8

2004 2005 2006 2007 2008 2009 2010 2011

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18.827.7

37.4

57.867.1 67.9

92.3101.0

2004 2005 2006 2007 2008 2009 2010 2011

Europe

2.2 5.4 10.014.9

24.3

37.444.5

52.2

2004 2005 2006 2007 2008 2009 2010 2011

China

2.0 2.9 4.7 5.6 4.7 4.2 7.6 12.3

2004 2005 2006 2007 2008 2009 2010 2011

India

7.2 8.0 8.0 10.1 11.0 12.118.4 21.1

2004 2005 2006 2007 2008 2009 2010 2011

ASOC (excl. China & India)

0.4 1.9 4.39.3 12.7

7.3 6.9 7.5

2004 2005 2006 2007 2008 2009 2010 2011

Brazil

1.3 3.3 3.3 4.7 5.4 6.4 11.0 7.0

2004 2005 2006 2007 2008 2009 2010 2011

AMER (excl. US & Brazil)

0.3 0.4 1.6 1.9 3.7 3.1 6.7 5.5

2004 2005 2006 2007 2008 2009 2010 2011

Middle East & Africa

Source: Bloomberg New Energy Finance, UNEP (MENA highlight added)

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9. Similarly, the sectorial pattern of investment is heavily skewed with solar and wind accounting for 90% of the total. Investment in solar power jumped 52% to $147bn in 2011, an amount almost twice the investment in wind power, which fell by 12%. As shown in Figure 3, developed countries stood far ahead in solar investment, while developing economies retained their lead in wind farm investment. Strikingly, developed countries’ performance took place notwithstanding the shakeout and the wave of bankruptcy filings that hit the solar manufacturing industry. In this unfortunate context, investment growth has largely been attributed to a surge in large‐scale solar thermal electricity generation projects in Spain and the US and, in the wake of falling panel prices, to still buoyant rooftop PV markets in Germany and Italy.

Figure 3: Investment by Form and Economic Region ($bn)

0.2/

1.8/

0.3/

5.0/

6.3/

37.1

117.4

0.1

1.1

5.5

1.8

4.3

46.7

30.0

Marine

Geothermal

Small hydro

Biofuels

Biomass & w‐t‐e

Wind

Solar

Developed Developing

52%

‐5%

‐5%

59%

‐20%

‐12%

‐12%

Total growth

Source: Bloomberg New Energy Finance, UNEP

10. Two major and contrasting features dominated the renewable energy landscape in 2011: falling technology costs and weakening policy support. On the one hand, prices of photovoltaic panels fell by almost half in 2011, while the costs of onshore wind turbines decreased by up to 10%. Comparison based on ‘levelized cost of electricity (LCOE)’ – a metric not found in the report’s glossary but tentatively defined in Footnote 4 of the present review –

4 indicates that these two leading renewable power technologies are closing the gap with fossil fuel generated electricity. On the other hand, the weakening of supportive policies was most observable in developed countries where fiscal austerity, banking instability and, in the case of the US, legislative deadlock, have all acted as serious impediments to investment and financing.

11. This policy hiatus comes at a time when fully competitive renewable power is starting to be seen as a truly viable option. Hence the overriding message from this year’s report is that despite a record investment in renewables, the risks to future growth have heightened. Within lagging MENA, risks of a different nature have already occurred.

Trends and Policy Issues within MENA

12. Despite some tentative advances in the region, progress has generally been disappointing. According to the report, total renewable energy investment in the Middle East and Africa reached $5.5bn in 2011, representing 2.1% of the world total. This poor performance was made even worse by a fall in investment of 18% compared with 2010. Within MENA per se, policy uncertainty created by socio‐political turmoil in parts of the region has delayed a number of projects. However, important initiatives did progress in countries spared by the turbulence such as in Morocco and the UAE, where investment reached $1.1bn and $0.8bn, respectively. In

4 For a given electricity generation system, LCOE is the price at which the present value of revenues from the system’s output equals the present value of capital and operating costs. Contrary to a breakeven price, LCOE should not factor in specific policy support (tax, subsidy, etc) and financing structure (equity‐debt ratio).

other countries, where policy makers have announced ambitious goals, investment has so far been too small to appear in global statistics.

13. Worth considering in the context of MENA is the report’s assertion that rapidly falling costs of technologies have made solar power an economically viable alternative to oil‐fired turbines and off‐grid diesel engine generators. Indeed, assuming oil products are valued at international prices, positive return can be expected for solar power when factoring in the opportunity costs associated with burning oil. However, this argument is debatable in the case of oil exporting countries. The debate is around which of the following opportunity cost arises: foregone export revenues, foregone returns on capital invested to maintain a spare capacity (if any), or foregone expected net present value to future generations.5

14. Equally unsettled are the disincentives built into electricity price subsidies. Thus, solar deployment within MENA will be at best limited to utility‐scale developments. Indeed, it is hard to imagine homeowners and businesses rushing to install solar panels on their rooftops at costs still far above the electricity price charged by utilities. In this regard, Figure 4 indicates which countries around the world have reached (2012) or are likely to reach (2015) ‘socket parity’. Countries with higher electricity prices, such as Germany, Denmark, Italy, Spain and parts of Australia have already done so. With the LCOE of PV trending lower, a number of other countries will do the same in 2015, including the UK, Japan, France, Brazil, Turkey and California. Obviously, most MENA countries (Saudi Arabia being shown as an outlier in Figure 4) are likely to remain too far distant from that possibility.

Figure 4: Residential PV price parity

$/kW

h

Source: Bloomberg New Energy Finance

Conclusions

15. The present review has been undertaken to gain insight into investment and financing trends in global renewable power, as well as the challenges facing the industry. The review has been further extended to include a discussion of trends and policies within a lagging MENA region and to bring into focus issues overlooked or misunderstood. While the general premise of the argument that the economics of renewables can be improved by factoring in opportunity costs is evident, the determination of those costs in specific MENA cases is less obvious. Similarly, the idea that solar power can be fully deployed within MENA ignores the disincentives created by heavily subsidized electricity prices. These issues may after all be beyond the report’s scope; but surely, they are within the remit of MENA policy makers who have yet to reconcile them with their stated ambitious renewable energy goals.

5 In Saudi Arabia for instance, oil burnt in power generation is essentially priced at parity with natural gas, ie $0.75/MBtu, equivalent to a little less than $4.5/barrel, on the ground that the opportunity cost of using oil, in the presence of spare capacity, does not equate to the export price.

Economic Commentary Volume 7 No 8‐9, August‐ September 2012

© Arab Petroleum Investments Corporation Page 29/42 Comments and feedback to aaissaoui@apicorp‐arabia.com

Fiscal Break‐Even Prices Revisited: What More Could They Tell Us About OPEC Policy Intent?

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey (MEES) dated 13 August 2012. The views expressed are those of the author only. Comments and feedback may be sent to <aaissaoui@apicorp‐arabia.com>.

1. Unarguably, oil producing countries’ fiscal positions are far from being a determinant of international prices. Yet energy economists – especially oil market analysts – are tempted to embrace the concept of a fiscal break‐even price, realizing that it could provide a useful guide to price and production policies within the Organization of the Petroleum Exporting Countries (OPEC). In this context the concept is commonly defined as the oil price that balances government’s budget.

2. In light of significant budgetary changes in key OPEC member countries, in particular the expansion of spending programs in Saudi Arabia and the contraction of fiscal revenues in Iran, we have updated our previous findings.1 While focusing our efforts on improving the underlying modeling assumptions, as well as data collection and interpretation, we have kept to the methodological framework developed in the past. This consists of articulating short term and long term approaches to assess current fiscal positions and future fiscal sustainability.

Current fiscal positions

3. The fiscal sphere is of particular concern to OPEC governments, as revenue receipts and public spending have a major impact on their national economies. Figure 1 suggests that governments’ budget and extra‐budget spending are mostly funded from hydrocarbon rent. The rent – simply defined as revenue above industry costs and returns – is captured through royalty and hydrocarbon taxes. It flows to the fiscal sector together with non‐hydrocarbon fiscal revenues as well as investment income from current account surpluses put in a sovereign wealth fund (SWF). All or part of these revenues are spent on public goods, ie security, health, education, social infrastructure and other welfare programs, not to mention public debt servicing.

Figure 1: A Typical OPEC Government’s Fiscal Sector

Hydrocarbon taxes[y(Ep ‐ C)]

Royalties[xQp]

APICORP Research

Stabilization fund [SF]

Domestic oil and gasdemand

[D]

Budgetrevenues

Hydrocarbonproduction

[Q]

Hydrocarbonexports

[E = Q – D]

Extra‐budgetary transactions

Non‐hydrocabontaxes

Budget expenditures

Budget and extra‐budget operations

Total fiscal revenues

Sovereign wealth

fund [SWF]

1 MEES, 14 March 2011.

4. Accordingly, a fiscal break‐even price is the oil price that contributes to balancing the budget and extra‐budget operations illustrated in Figure 1. Starting with the simple identity that government’s expenditures should equal hydrocarbon fiscal revenues (HFR) plus non‐hydrocarbon fiscal revenues (NHFR) plus any contribution from a SWF, we derive from Equation 1 in Box 1 a fiscal break‐even price in Equation 2. In doing so, we assume no exchange rate effect. It is worth noting in this regard that hydrocarbon exports, from which derive the bulk of fiscal revenues, are generally denominated and paid in dollars, while government budgets are run in national currencies. Therefore, the effects of exchange rate on balancing the budget should not be ignored in other contexts.

5. Assuming returns from SWF are re‐invested and budgets are balanced (no flows to and from the stabilization fund SF), government’s budget revenues are reduced to hydrocarbon fiscal revenues (royalties and hydrocarbon taxes) plus non‐hydrocarbon taxes. In this case, and as indicated in Equation 2 (Box 1), the break‐even price can be presented as a quotient of two elements. The numerator is the algebraic sum of government expenditures, non‐hydrocarbon fiscal revenues and the portion of costs incurred by the hydrocarbon industry, pro‐rata share of taxes. The denominator is the sum of pro‐rata share of royalty and taxes of respectively commercial production and exports. Furthermore, as the break‐even price is expressed in terms of the value of the OPEC basket of crudes, an adjustment factor α is introduced to take into account the price differentials of crude oil, oil products and natural gas, relative to that value.

Box 1: Modeling The Fiscal Break‐Even Price

Using the framework described in Figure 1, we derive annual government's budget revenues (GBR) as:

GBR = xQαp + y[Eαp –C] + NHFR + rSWF + ΔSF [1]

Where:

Q is commercial production of hydrocarbon;

E is hydrocarbon export;

C is the hydrocarbon industry's full‐cycle cost;

NHFR is non‐hydrocarbon fiscal revenue;

r is the return on SWF;

SWF is the value of financial assets accumulated in a Sovereign Wealth Fund;

ΔSF is the flow to and from a Stabilization Fund;

x is hydrocarbon production‐weighted royalty rate;

y is the average rate of hydrocarbon taxation;

p is the average oil export price.

Assuming returns from SWFs are re‐invested and ignoring, as justified in the text, ΔSF, we derive the fiscal oil break‐even price, from equation 1, as:

p = α‐1 (EXP – NHFR +yC)/(xQ +yE) [2]

Where:

EXP is budget and extra‐budget expenditures

α is an oil‐natural gas price adjustment factor relative to the value of OPEC basket of crudes.

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6. The above model is relatively straightforward to implement. However, gathering and analyzing the needed data can be tedious and frustrating. In particular, fiscal data are tied to the tracking of budget revisions found in supplementary and complementary budgets. They further depend on the degree of transparency of extra‐budgetary transactions that prevailing institutional arrangements fail to capture entirely.

2 Just as problems with cost data arise from the need to develop a full life‐cycle cost view of hydrocarbon production. In addition to the cost of producing and supplying hydrocarbons to the markets, this should factor in the costs of finding and developing new reserves to replace those produced.

7. Once countries’ break‐even prices are computed, it is easy to generate a fiscal cost curve. As shown in Figure 2, a reasonable approximation to such a curve is obtained by ranking each OPEC country output (oil, NGLs and GTL), from lowest to higher price. The curve provides timely insight into the fiscal challenge facing some countries (or the investment opportunities offered to others) when market prices are lower (or higher) than their break‐even prices. It also provides some hints about the production policy options available to different members within OPEC, which are examined further below. Before that, the large inter‐country variations and intra‐country estimate ranges displayed in Figure 2 require some explanation.

Figure 2: Fiscal Cost Curve for 2012 [Bar width: country’s production; bar heights: price estimate ranges]

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8. Median estimates of fiscal break‐even prices for 2012 vary from $53 per barrel for Qatar to $127 per barrel for Iran. In between, Saudi Arabia’s break‐even price is estimated at $94 per barrel, slightly lower than the OPEC output‐weighted average of $99 per barrel. Explanations for these inter‐country variations include differences in the structure and cost of the hydrocarbon industry as well as the degree non‐hydrocarbon fiscal revenues contribute to balancing budgets. Additionally, different structures of exports translate, in the current market context, into a price adjustment factor (α) varying from basically 1 for non‐gas exporters, such as Saudi Arabia, to about 1.35 for Algeria and 1.45 for Qatar. Furthermore, intra‐country sensitivity analysis reflects revenue and spending uncertainty, which is, obviously, greater in the case of Iran.

2 Richard Allen and Dimitar Radev, “Extrabudgetary Funds”, IMF, Technical Notes and Manuals, Fiscal Affairs Department, June 2010.

9. These individual differences notwithstanding, OPEC’s weighted average fiscal break‐even price stays within a relatively narrow range of $90‐110 per barrel. Evidence that the most influential member, Saudi Arabia, lies within that range strengthens the chances of making the fiscal break‐even price a reliable predictor of price preference for OPEC as a group.

10. Member countries’ contrasting preferred prices are a reflection of their heterogeneous and, for some, uncertain fiscal positions. Those whose fiscal break‐even prices are higher than market price should not be expected to be comfortable with status quo. They would try and persuade the opposite side to lower the aggregate production ceiling and individual output quotas either pro‐rata or otherwise. The expectation would be for market prices to increase to meet their higher break‐even prices, even if that means losing some volume. The problem, however, would not so much be of implementation. After all, OPEC members have grown fairly skilled at handling complex bargaining. Rather, it is how to validate and justify it in the first place.

11. The ultimate truth is that no OPEC member can set expenditures which depend on other members surrendering market share. Furthermore, countries would just spend what they could afford. As stated by John V Mitchell, high spenders have no escape but to adjust their fiscal policies and bring their spending closer to their revenues. As a matter of fact, their preferred prices are more an indication of their preferred spending than any price they are likely to achieve.

3

Future fiscal sustainability

12. In contrast to the short term approach, where break‐even prices have tentatively been estimated on a country‐by‐country basis, the long term approach models OPEC as a group. Furthermore, instead of computing new fiscal break‐even prices, we hold constant the weighted average range of $90‐110 per barrel found previously to determine whether it could sustain future stable levels of spending for the group.

13. From this perspective, our assessment of fiscal sustainability derives from Milton Friedman’s permanent income hypothesis (PIH). In its usual formulation, PIH states that the choices made by consumers regarding their consumption patterns are determined not by current income but by their longer term income expectations. Translated to governments – provided they are forward looking – Dr Friedman’s premise would mean that their spending is akin to consumption and therefore would be determined in a similar way. Under this assumption, sustainable government spending would be approximated by the annuity value of expected revenues. Formally, such a stable spending would be determined using Equation 3 in Box 2. It is the net return on both financial assets (stemming from current account surpluses) accumulated in a SWF and the net present value of fiscal revenues, the bulk of which are expected from the exploitation of the remaining proven reserves.

3 Paraphrased from an email sent by John V. Mitchell, co‐author with Paul Stevens of “Ending Dependence ‐ Hard Choices for Oil‐Exporting States”, Chatham House, London: 2008.



14. It should be noted that alternative models exist. While adhering to a permanent income that relates producers’ fiscal policy to their hydrocarbon wealth, our preference goes to the aforementioned model. This is in contrast to using the non‐hydrocarbon balance as a key indicator of long term fiscal sustainability. Indeed, the different definitions of the non‐oil balance adopted, which depend on the purpose for which this indicator is used, make estimates hardly comparable.

4

15. The main determinant involved for calculating the annuity value (sustainable government spending) is OPEC depletion policy and the resulting production profile. Despite revising its projections downward on concerns of lower demand growth and further uncertainty about the extent of non‐OPEC supply from unconventional sources, OPEC does not anticipate a plateau for its crude oil, NGLs and GTL before 2035. At that horizon, the call on OPEC would be 49.3mn b/d in the ‘Reference Case’,

5 slightly higher than the 48.7 mbd of the IEA’s central scenario – the ‘New Policies Scenario’.6

16. Other important determinants of fiscal revenues include export prices, governments’ fiscal take, discount factor and long term population dynamics. They are calibrated as summarized in Table 1 and briefly expounded upon below.

4 For an extended discussion of this approach, see Paulo Medas and Daria Zakharova, “A Primer on Fiscal Analysis in Oil‐Producing Countries”, IMF Working Paper WP/09/56, March 2009. 5 OPEC, World Oil Outlook, 2011. 6 IEA, World Energy Outlook, 2011.

Table 1: Basic Assumptions for OPEC Revenue Simulations

Reference date: 2011 Assumptions Remarks

Proven hydrocarbon reserves 254 Gtoe + 25% reserve growth and Y‐to‐F Y‐to‐F: Yet to find from undiscovered resources

R/P ratio 113 years Simulation horizon : 2100

Petroleum production profiles Crude oil & NGLs Tuned to OPEC's Reference Case to 2035 (2011 WOO)

Hydrocarbon export prices 0.70 of OPEC basket vakue Prices moving together in the long run

Domestic pricing At average cost No rent extracted on domestic consumption

Governments’ take 70% of export take Past 5‐year calibration, declining to 60% in 2035

Discount factor 5% real Up‐pricing of risks ‐ Long term horizon

Population 410 million, doubling in 2050 Dynamics depends on labor imports in OPEC's GCC

APICORP Research using statistics from OPEC, IEA, BP and own assumptions

OPEC proven hydrocarbon reserves have been revised upward to 254 billion tons of oil equivalent (toe), at the end of 2011. These reserves are 66% crude oil and NGLs and 34% natural gas. Yet‐to‐find would raise proven reserves by 25%.

The R/P ratio (proven reserves over production) is about 113 years at the end of 2011. As it is static, this ratio is not used to indicate a time to depletion but to justify the long‐term timeframe for the analysis up to 2100.

Hydrocarbon exports are valued at international prices. The ratio of the average export price to the value of the OPEC basket of crudes, taken as a reference price, is 0.70.

Domestic energy supply of oil products and natural gas is valued at cash cost.

As a result of rising costs, government’s fiscal take is assumed to decline from 70% of the total value of exports in 2011 to 60% in 2035 for OPEC as a whole.

The discount factor of 5%, which reflects both time preference and risk, is concurrent with a very long‐term horizon.

Finally, to factor in the effect of population dynamics, our calculations and results are expressed in per capita terms. In this regard, despite a continuously decreasing rate of growth, OPEC’s population is expected to double by mid‐century from the current level of some 410 million.

17. On this basis, Figure 3 illustrates a baseline scenario, tuned to current OPEC’s ‘Reference Case’. Combined oil and natural gas production profile reaches a maximum of 3.715bn toe in 2035, beyond which aggregate hydrocarbon exports start to decline. The falling off after a 10‐year plateau is moderated by the greater weight of gas production in the long term. Another critical time occurs when domestic demand exceeds production around 2065 and, as a consequence, hydrocarbon rents dry out. Obviously, some member countries would face declining exports much sooner than 2035.

Figure 3: Baseline Production Profiles

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Box 2: Fiscal Sustainability – Using PIH

The economic literature on the use of Milton Friedman’s Permanent Income Hypotheses (PIH) is extensive, but dominated by the IMF’s empirical case studies.

PIH provides a simple framework for assessing fiscal sustainability. Accordingly, sustainable government spending (GC), at any time t, is determined by the annuity value of expected financial and hydrocarbon revenues as expressed in equation 3:

GCt = GC = r [SWFt‐1 + ∑ HFRt+n (1+d)‐n] [3]

n=0,N Where:

SWFt‐1 is the value of financial assets accumulated in a sovereign wealth fund at the end of the previous year, in constant prices;

FRn is the fiscal revenue in period n, both hydrocarbon (captured through royalty and taxes) and non‐ hydrocarbon, in constant real prices;

r is the expected real rate of return on SWF;

d is the discount factor,

N is the number of years until hydrocarbon reserves are depleted.



18. Notwithstanding the implicit trend that may be inferred from Figure 3, that prices might rise above inflation, the resulting simulations are based on the adopted range of $90 per barrel to $110 per barrel kept constant in real terms. As expressed in Equation 3 (Box 2), the annuity values are computed as returns on both the value of accumulated financial assets and the net present value (NPV) of hydrocarbon fiscal revenues.

19. The resulting values are plotted in Figure 4 for both oil price bounds as a function of the NPV discount factor. To simplify this figure, the discount factor has been identified with the rate of return. Otherwise, the interpretation of results would have been hampered by the co‐existence of the two interest rates. However, these rates should not be confused with each other. The former, which reflects time preference, is used to discount future fiscal revenues. The latter is used to predict future returns from investing current account surpluses. Raising the first rate lowers the net present value of fiscal revenues (NPVFR) on which the annuity is based, whatever the investment return; raising the second adds to the annuity, whatever the NPVFR.

Figure 4: Annuity Values of Expected Fiscal Revenues

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20. What Figure 4 attempts to capture is the difference between expected and realized income. It shows the range of per capita annuity values corresponding to a discount factor of 5% and an oil price of between $90 per barrel and $110 per barrel. Values in that range are about 50% to 70% above the historical 50‐year average real per capita of $1,120. 7 This should not come as a surprise considering the long hydrocarbon industry depression that lasted from the early 1980s to the early 2000s. Furthermore, while per capita averages had been slightly lifted by recent upward trends in oil prices, returns from SWF investments were being adversely impacted by the global financial crisis and aftermath. Far more important, however, is whether the results shown in Figure 4 should be interpreted as an indication that OPEC, as a group, will be fiscally more comfortable in the long run. This question cannot reasonably be answered without a more thorough investigation into governments’ future patterns of spending and revenue, which is well beyond the scope of this analysis.

7 All real values have been computed using OPEC’s inflation and currency adjustment methodology and data.

Conclusions

21. In light of significant budgetary changes in key countries, we have provided an update of fiscal break‐even prices within OPEC. Keeping to our traditional two‐step analytical framework we have estimated current levels, then testing whether, if held constant in real terms, they could sustain future stable governments’ spending.

22. In the first part of the analysis we have re‐drafted the fiscal cost curve for OPEC member countries in an attempt to shed timely light on the likely individual and group policy behavior. On the one hand, it can be claimed that fiscal break‐even prices are dependable predictors of price preferences within the group. On the other hand, member countries’ failure to develop a common policy may be attributed to their heterogeneous and, for some, uncertain fiscal positions. This is no matter how close to OPEC’s weighted average fiscal break‐even price – currently in a range of $90‐110 per barrel – the most influential member, Saudi Arabia, may be.

23. In the second part we have focused on an inter‐temporal fiscal sustainability analysis, assuming OPEC – taken as a group – would be investing its surplus funds in financial assets. In doing so we have implicitly admitted that the bulk of budget spending are current expenditures that yield no long term returns. The consequence is that spending is implicitly kept low to enhance future financial returns. If we assume instead that government expenditures include a non‐negligible investment component then spending upfront may be a better course of action. This is valid provided the returns from domestic social and physical investment are higher than those from financial investment abroad. Using oil and gas revenues today to diversify their economies and progressively shift their reliance away from hydrocarbons may enable OPEC member countries to secure a more viable and sustainable economic development. Whatever their resulting spending patterns might be, it would affect their fiscal break‐even prices and hence their oil price preferences and production policy intents. The challenge that still remains is to translate these intents into a common and credible policy.

Year‐to‐Date Issues of APICORP’s Economic Commentary

‘APICORP’s Review of MENA Energy Investment: Sustained Outlook despite Lingering Uncertainty’, January 2012.

‘IEA’s World Energy Outlook: Review and Discussion of MENA Deferred Investment Case’, February 2012.

‘MENA Energy Investment in a Global Setting Assessment and Implications for Policy and Long‐term Planning’, March 2012.

‘MENA Power Reassessed: Growth Potential, Investment and Policy Challenges’, April‐May 2012.

‘Is the Anticipated Rise in Long‐term Oil Price Inevitable?’, June 2012.

‘Global Trends in Renewable Energy Investment: A Review of the Frankfurt School‐UNEP’s Report and Discussion of the MENA Case’, July 2012.

‘Fiscal Break‐even Prices Revisited: What More Could They Tell Us About OPEC Policy Behavior?’, August 2012.

Economic Commentary Volume 7 No 10 ‐ October 2012

© Arab Petroleum Investments Corporation 2006 /42 Comments or feedback to aaissaoui@apicorp‐arabia.com

MENA Energy Investment Outlook: Capturing the Full Scope and Scale of the Power Sector

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 5 October 2012. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com.

1. As usual during this period of the year, our commentary presents APICORP’s main findings of its rolling five‐year review of energy investment in the Middle East and North Africa (MENA).

1 While continuing to extend the oil and gas value chains to include the generation of electricity, we have managed for the first time to capture the full scope and scale of the power sector by adding capital requirements in transmission and distribution (T&D). Naturally, in order to maintain a coherent set of reviews past series have systematically been revised accordingly.

2. The immediate context of the 2013‐17 review is the protracted socio‐political turmoil in parts of the region and the negative perception it has created for investment. In the larger context, despite a weak global economy and declining oil demand, the review assumes that OPEC will be able to keep the value of its basket of crudes near its members’ output‐weighted average fiscal‐breakeven price of about $100/bbl.

2 Investment climate permitting this should encourage the development of oil‐based projects. For natural gas, while domestic‐oriented projects are likely to go ahead no matter what, export‐oriented projects face significant market uncertainty. Not only have international gas prices greatly deviated from oil parity, but they have kept diverging between regional markets. Looking forward we assume that natural gas prices will evolve between $3‐$5/MBtu in fully liberalized markets with abundant domestic supplies and $12‐15/MBtu in markets relying on imports under traditional long‐term contracts.

3. Against this background, this commentary is in three parts. Part One presents the review methodology. Part Two outlines the new trends that shape the outlook. Part Three extends the discussion to the major challenges facing investors ahead.

Review Methodology

4. Our review is exclusively concerned with domestic and intra‐regional energy investment along the oil and gas value chains and their main links, ie the upstream, midstream and downstream. In addition to including petrochemicals, the downstream is extended to the power sector. As noted in the introduction, contrary to previous analyses, which focused on the generation link of the electricity value chain, investment is extended to the transmission and distribution (T&D) systems. Except for the growth‐driven power generation link, which implicitly includes the nascent power generation capacity from renewables and nuclear, the review is basically project based. This requires maintaining a database of more than 200 planned (and announced) public and private projects whose costs range from $100mn to $20bn. While the database tracks ventures at different stages of the project life

1 As usual, MENA is defined to include the Arab world and Iran. Despite progress to demarcate borders and delineate oil deposits, energy investment in Sudan is kept inconsequentially aggregated with that of South Sudan. 2 For more details see Ali Aissaoui, “Fiscal Break‐Even Prices Revisited: What More Could They Tell Us About OPEC Policy Intent?”, MEES, 13 August 2012.

cycle, the review only takes those likely to reach a final investment decision. This is within a five‐year timeframe, which corresponds to the rolling planning period of most project sponsors.

5. The systematic repetition of the review, year after year since 2003, has been instrumental in identifying key trends and patterns. This is so even though the review no longer differentiates between potential investment and actual capital requirements as it did during the global financial crisis and immediate aftermath.3 We have considered indeed that projects sponsors have had ample time to bring back shelved projects that are still viable. Finally, an important feature of the methodology is that energy demand and prices are implicit determinants of investment. Quite the opposite, project costs, feedstock and funding are explicit constraints.

Investment Outlook

6. Within this framework, MENA energy capital investment is expected to add up to $740bn for the five‐year period 2013‐17. Compared to past assessments, which have been uniformly and consistently revised to reflect the full scale and scope of the power sector, investment appears overall on the rise again, driven mainly by costs and a catch‐up effect. Indeed, for reasons discussed in the third section of this commentary, our ‘average project cost’ index, which has been subdued in the wake of the global financial crisis, is once again on an uptrend. However, the current amount of investment should not be considered as particularly high since it is comparable to the nominal peak identified in 2009 when completing the 2010‐14 review (Figure 1).

Figure 1: Rolling Five‐Year Reviews of MENA Energy Investment (Series revised to reflect the full scope and scale of the power sector)

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7. Not unexpectedly, lingering socio‐political turmoil in parts of the region has hampered investment decisions and project implementation. As a result, investment has fallen below potential in countries affected by the turmoil. This has somewhat distorted the geographical pattern of investment. A little more than three quarters of energy capital investment are shared by

3 Between 2007 and 2010 the review framework was amended in an attempt to reflect the huge uncertainty created by the global financial crisis. As a result, our findings fell into two categories: potential investment (originally secured through FDI); and actual capital requirements (what is left after deducting shelved projects).

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seven countries among the biggest holders of oil and gas reserves which have not faced such turmoil. These exclude Libya but include Iraq, notwithstanding its enduring troubles.4 In Saudi Arabia, investment is projected to reach $165bn, mostly engendered by Saudi Aramco, SABIC and its affiliates as well as Saudi electricity company (SEC), as stand‐alone domestic private investors have continued to struggle to attract capital. The UAE has established itself for the second consecutive review as the region’s second largest investor, with projects worth $107bn. Pending further implementation decisions Algeria has jumped in the region’s rankings, overtaking both Qatar and Iran as the third potential investor. As investment readiness has gained momentum in the wake of the restoration of good governance within Sonatrach, capital requirements – largely the result of catch‐up investment – have reached $71bn. In contrast, tighter international sanctions, and the retreat of foreign companies, have ended up taking a toll on Iran’s elusive energy investment program, which has tentatively been put at $68bn. Finally, despite moving up the rankings ahead of Qatar and Kuwait, Iraq with $56bn worth of capital requirements is still far below its huge potential.

Figure 2: Country Pattern Across Previous and Current Reviews

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APICORP Research using internal database* Sudan: Aggregate (see footnote no. 1)

8. In Iraq, the reaffirmation of the vital need to achieve the full development of the oil and natural gas sectors has yet to be translated into coherent policies and actions. In particular, the Iraqi Federal Government (IFG) has to pass a long‐awaited package of hydrocarbon legislation. This will hardly be possible if IFG and the Kurdistan Regional Government (KRG) fail to come up with a complete and thorough understanding of their pending oil issues. Furthermore, IFG needs to alleviate infrastructure bottlenecks and develop better solutions to counter recurrent security threats.

9. Under‐investment, which has been particularly apparent in Kuwait, is now the case in Qatar as well. In Kuwait, government policy has often been at odds with parliamentary politics and efforts to align the two have been repeatedly frustrated. As a result, major components of the upstream development continue to be questioned and key downstream projects such as the long‐delayed giant al‐Zour refinery are still striving for materialization. In contrast, Qatar’s stagnation is the result of the lack of a pure

4 The biggest MENA holders of combined oil and natural gas reserves in decreasing size are: Iran (50.0 Gtoe), Saudi Arabia (42.8), Qatar (25.8), Iraq (22.3), UAE (18.5), Kuwait (15.1), Libya (7.7) and Algeria (5.7) (source of data: BP Statistical Review of World Energy, June 2012).

policy decision on whether or not to extend the ongoing moratorium on further development of the North Field, beyond the domestic market oriented Barzan project. As a result, and despite a shift in emphasis on enhancing oil recovery and expanding the petrochemical industry, energy investment in Qatar has lost momentum.

10. As already noted, investment has been affected to different degrees in countries still facing political and economic uncertainties and/or a precarious environment. This is the case in Egypt, Libya and to a larger extent Yemen. In these countries investment in capacity expansion is likely to be back‐ended towards the end of the review period as investors have adopted a wait‐and‐see attitude. Much more critical is the case of Syria, where investment has come to a complete halt and is unlikely to resume as long as armed violence continues. In any case, investment in this country is expected to be mostly in repairs, rehabilitation and recovery of destroyed or damaged energy infrastructure.

11. Capturing the full scope and scale of the power sector and adjusting for the inclusion of the T&D systems has reshaped the sectorial distribution of investment. As a result, each of the oil, gas and power value chains now accounts for a third of the region’s total. In the hydrocarbon sector the gas downstream link has declined as a result of Qatar’s moratorium and the consequent pause in its LNG and GTL expansion program (Figure 3). In contrast, the oil downstream link, where investment is mostly driven by Saudi Aramco’s program of large scale integrated refining/petrochemical facilities, has performed well. Much more impressive, however, is investment in power. In this sector capital requirements have been on a steady rise and are expected to accelerate during the current review period.

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Figure 3: Sectoral Pattern Across All Reviews

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12. Notwithstanding sustained expansion of investment, power supply has fallen short of needs. To catch up with unmet potential demand, medium‐term capacity growth, which has been worked out on a country by country basis, is expected to be much higher than that of economic output: 7.8% for the period 2013‐17 against 4.5% for GDP. As detailed in the Box below, this would require an investment of about $250bn, 59% for new generation capacity and the remaining 41% for T&D.

5 Investments in nuclear and renewables (mostly solar) are implicit and reflected in the average capacity cost in relevant cases. For nuclear, while Bushehr plant in Iran has been adding electricity to the national grid since September 2011, Abu Dhabi’s first such a plant is not expected to be commissioned during the review period.



Major Challenges

13. Investment of the magnitude found in the present review will not occur without addressing current challenges, prominent among which are cost, fuel/feedstock and funding. These challenges, which are considered far beyond the scope and resources of any project sponsor, are discussed next.

14. 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, has resumed its upward trend after somewhat stabilizing in the middle of the global financial crisis. However, the relatively moderate 7% upward trend underpinning the current review should not mislead. The extent to which project costs are predictable depends on the outlook for the price of engineering, procurement and construction (EPC) and its components. As shown in Figure 4, these include the prices of factor inputs, contractors’ margins, project risk premiums and an element that mirrors general price inflation in the region. Not to mention the cost of what we have dubbed ‘excessive largeness," the documented fact that large‐scale projects tend to incur significant delays and cost overruns. Energy project costs would have certainly quadrupled during the last ten years, if not for the dampening effect of the global financial crisis. The likelihood is that costs will continue rising. However, despite efforts to quantify in a meaningful way each of the above mentioned parameters, we have found it difficult to infer how far up and for how long the overall cost trend is likely to be when combining all components.

Figure 4: Large‐scale Energy Project Cost Structure

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15. The next challenge is the supply of fuel/feedstock ‐ primarily natural gas to the petrochemical industry and the power sector. Our main findings are that while aggregate MENA proved gas reserves are substantial and their dynamic life expectancies are fairly long, the acceleration of depletion appears to have reached a critical rate for more than half the gas‐endowed countries. 6 If production continues not to be replaced in Bahrain, Kuwait, the UAE and to some extent Saudi Arabia it could lead to a supply crunch (obviously sooner rather than later in Bahrain). Libya, Yemen and Iraq ‐ although Iraq can still increase supply by cutting down on gas flaring ‐ face a similar prospect (Figure 5).

6 Ali Aissaoui, “MENA Natural Gas: A Paradox of Scarcity amidst Plenty”, MEES, 27 December 2010.

Box: MENA Investment in the Power Sector (*)

B1. Many countries within MENA have been struggling to meet fast‐growing demand for electricity, a consequence of high population growth, fast expanding urban and industrial sectors, increasing needs for air conditioning, and heavily subsidized electricity tariffs. With ongoing turmoil in parts of the region, catching up with unmet demand may be perceived as socially and politically more desirable.

B2. In the absence of active demand side management, this will entail a capacity growth of 7.8% per year, which translates into a five‐year increment of 124GW above the 2012 level. Therefore, with current reference costs – reflecting prevailing prices of engineering, procurement and construction (EPC) and country investment climates – the capital required will be in the order of $148bn for 2013‐17. As shown in the table below, the GCC area, which will continue to grow at the highest rate, accounts for 43% of MENA total and 53% of the Arab world total (expenditure for nuclear power generation is implicit for the UAE).

2011* installed capacity (GW)

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growth (%)

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requirements (G$)

Maghreb 1 32.0 112.8 7.4 14.6 17.6 Mashreq 2 60.7 294.1 7.6 29.1 36.8GCC 3 104.8 461.6 8.5 57.0 63.1Rest of Arab world 4 4.4 15.6 6.6 1.8 2.3Iran 49.7 227.0 7.0 21.4 27.8

MENA Total 251.6 1111.1 7.8 123.9 147.6* 2011: estimates 1 Maghreb: 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 Rest of Arab world includes Sudan and Yemen, but excludes Comoros, Djibouti and Somalia for lack of data.

Compilations and projections by APICORP Research B3. But power generation comes with T&D systems. This derives from the need to develop networks to supply electricity to industries, businesses and households. Transmission grids consist of high voltage lines designed to transfer bulk power from generation plants to large industrial customers and distribution centers, generally over long distances. In contrast, the function of low voltage distribution grids is to supply power to final consumers in urban and, whenever socio‐economically desirable, in rural areas as well. Under this grid‐based supply perspective, MENA T&D investment amounts to $103bn for 2013‐17, with further breakdown given below.

Total Investment in MENA Power Sector for the Period 2013‐2017 ($bn)

Investment in $bn Generation (G)

Transmission (T)

Distribution (D)

Total (T,D)

Total (G, T, D)

Maghreb 1 17.6 3.9 9.7 13.6 31.2

Mashreq 2 36.8 6.3 18.0 24.3 61.1

GCC 3 63.1 10.7 30.9 41.6 104.7

Rest of Arab world 4 2.3 0.5 1.3 1.8 4.1

Iran 27.8 6.1 15.3 21.4 49.2

MENA Total 147.6 27.5 75.2 102.7 250.3 1 Maghreb: 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 Rest of Arab world includes Sudan and Yemen, but excludes Comoros, Djibouti and Somalia for lack of data.

Compilations and projections by APICORP Research ______________ (*) For MENA power outlook analysis see Ali Aissaoui “MENA Power Reassessed: Growth Potential, Investment and Policy Challenges”, MEES, 30 April 2012.



Figure 5: Distances to Optimal Natural Gas Supply Pattern

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16. Uncertainties surrounding project costs and fuel/feedstock supplies are compounded by a marked deterioration of funding conditions, which is likely to further complicate the strategic decisions project sponsors in the region make with respect to investment and financing.

17. In a context of widespread deleveraging, the financing of energy projects is expected to be structured with less debt. On the one hand, the upstream, midstream and T&D systems in the power sector will continue depending heavily on internal funding in the form of either corporate retained earnings or state budget allocations. On the other, the hydrocarbon downstream, which has traditionally relied on debt, typically in a proportion of 70%, will need more equity. This derives from recent observations in the oil based refining/petrochemical link where the equity‐debt ratio has been 35:65. More compelling is the trend in the gas based downstream link where the ratio has been 40:60, almost certainly to factor in higher risks of feedstock unavailability. Similarly, in the power generation segment the debt ratio has been reset downward to reflect reduced leverage of projects developed by independent power and water/power producers (IPPs and IWPPs). As a result, the capital‐weighted average structure for the oil, gas and power value chains has been found to be 61% equity and 39% debt. This structure conforms to the trend observed since the onset of the global financial crisis, once adjustments to include T&D systems in the power sector have been made.

18. The shift in the energy capital structure does not diminish the challenge of meeting the demand for both equity and debt . On the one hand, we have estimated that any prolonged period of low oil prices (value of OPEC basket of crudes) below $100/bbl will affect internal financing for the upstream sector. On the other hand, funding prospects for the downstream, albeit less leveraged, are now highly uncertain. The total annual volume of debt of $58bn, which results from the capital requirements found in the current review and the likely capital structure highlighted above, is much higher than the record of $44bn achieved in the loan market in 2010 (Figure 6). Raising such amounts of debt in a context of a collapsing loan market and tightening lending conditions will hardly be possible. The resulting shortfall could even be larger if MENA public investment funds, which have stepped up their involvement in the local loan market in recent years, do not receive enough government support due to increasing social demands for public funds. 7

7 For further elaboration see Ali Aissaoui, “Financing MENA Energy Investment in a Time of Turmoil”, MEES, 13 June 2011.

Figure 6: Evolution of Loans To MENA Energy Sector (2012: inferred from nine‐month loan market performance)

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19. Finally, while general financing trends are common throughout MENA region, the case of Iran should be assessed based on its specific context. In this country, tougher economic sanctions are expected to continue to deter investors and severely restrict funding.

Conclusions

20. Our review of MENA energy investment has been broadened in order to capture the full scope and scale of the power sector. Accordingly, MENA total energy capital investment is expected to amount to $740bn for the five‐year period 2013‐17. Compared to past assessments, which have been consistently revised to fully reflect adjustments in the power sector, investment appears to be on the rise again. However, in a context clouded by sluggish global economic growth and protracted regional socio‐political turmoil, capital requirements have mostly been driven by a catch‐up effect and unrelenting escalating costs.

21. In this context, a little more than three quarters of energy capital investment are located in seven countries among the biggest holders of oil and gas reserves. Obviously, the geographical pattern has favored countries that have not faced the turmoil. On a sectoral level, adjustments in the rapidly expanding power sector have led to a more evenly distributed pattern between the three major value chains, i.e. oil, natural gas and power.

22. The review has also highlighted serious policy challenges. In addition to the deteriorating investment climate which forms the background of the review, three issues continue to confront investors: rising costs, scarcity of natural gas supply and funding limitations. Of the three, the latter is the most critical. Given the structure of capital investment stemming from the review, internal financing could only be secured if oil prices remain above OPEC’s fiscal break‐even price, which we have estimated to be around $100/bbl. In contrast, external financing, which comes predominantly in the form of loans, is likely to be daunting in face of dwindling lending resources. Faced with more pressing social demands, MENA governments may not be able to bridge the funding gap. Going forward policy makers in the region should focus their commitment on improving the investment climate and restoring investors’ confidence.

Economic Commentary Volume 7 No 11 ‐ November 2012


Strait of Hormuz : Alternate Oil Routes Not Enough

This commentary by Ali Aissaoui, Senior Consultant at APICORP, is published concurrently in the Middle East Economic Survey dated 26 October 2012. The views expressed are those of the author only. Comments and feedback may be sent to: aaissaoui@apicorp‐arabia.com.

1. The idea of researching and writing on this topic came to me on a trip I made after speaking at an international energy conference in Ras Al‐Khaimah (UAE) in early October. Instead of joining an optional technical visit, I decided to cross into Oman’s Musandam Peninsula where pods of dolphins make regular appearances offshore Khasab. However, to avoid disappointment, I lowered my expectations of spotting any large marine species. The odds were hat the 30‐nation, US‐led joint international mine‐sweeping drills that took place in the Strait a week before might have scared them away.

2. The drills were a response to repeated warnings by Iran that it would consider further tightening of economic sanctions or an attack on its nuclear facilities as a casus belli justifying the disruption of maritime traffic through Hormuz. Punctuated with missile tests and naval maneuvers, such threats have unsettled global oil markets and sparked speculation regarding the likelihood and potential consequences of them being carried out.

3. The Strait of Hormuz is a vital waterway for the world’s supply of oil as well as liquefied natural gas (LNG). It is a narrow channel – 21 nautical miles (39 km) at its choke point – between Oman and Iran. Ships use two lanes, one in each direction. Within the Strait proper, in Omani waters, each lane is two miles wide and both lanes are separated by a two mile buffer. As the lanes progress into the Gulf and cut through Iranian waters they become wider with a larger buffer.

Strait of Hormuz Shipping Lanes

Iran

UAEFujairah

Source: Tentatively improved from unknown source

4. Data on major trade movements from the BP Statistical Review of World Energy (June 2012) suggest that the volume of crude oil and oil products that transited through the Strait in 2011 was close to 17mn b/d, accounting for 31% of global

oil trade. Much less sizable, but equally important proportionally, LNG volumes amounted to the oil equivalent of 2mn b/d representing 33% of world LNG trade.

5. As far as oil is concerned, existing alternatives to Hormuz via pipelines involve Saudi Arabia, Iraq and the UAE. This leaves Iran, Kuwait, Qatar and Bahrain without any other option. Likewise, Qatar and the UAE have no substitute routes for LNG exports.

6. Saudi Arabia has long been operating the Trans‐Arabian Petroline system running east‐west to the Red Sea. The system, which consists of the Abqaiq‐Yanbu’ twin‐pipeline and storage facilities, has been upgraded several times to its current capacity of 5.1mn b/d of crude oil. Assuming throughput at about half of capacity, an unused 2.5mn b/d is probably being kept as reserve capacity. Also on standby is the 1.65mn b/d IPSA (Iraqi Pipeline Trans Saudi Arabia), which has recently been reconditioned to carry crude oil again. IPSA was laid across the kingdom in the 1980s during the Iraq‐Iran war. Later, it changed ownership to the Saudis who converted it to transport natural gas.

7. Less significant for the moment is Iraq’s export route to the Mediterranean through the Kirkuk‐Ceyhan system. While the nominal capacity of the twin pipeline is 1.6mn b/d, currently the smaller line is operated at a throughput of about half its 0.6mn b/d capacity. The major 1mn b/d line cannot be filled unless repairs are made, and the same applies to the reversible strategic north‐south pipeline.

8. Finally, the UAE has just put in operation the long‐delayed 1.5mn b/d Abu Dhabi Crude Oil Pipeline (ADCOP). ADCOP links Abu Dhabi’s onshore oil facilities in Habshan to Fujairah’s new oil terminal on the Gulf of Oman.

9. Therefore, while the combined operating capacity of the alternative routes is some 8.85mn b/d, spare capacity – taking into consideration both unused capacity and capacity additions made in 2012 – is just a little more than a third of the volumes that transited the Strait in 2011. The amount of oil being pumped through the pipelines can be raised by using drag‐reducing agents or so‐called ‘flow improvers.’ Even so, it is hard to argue that currently available alternatives are enough to alleviate the impact of a crisis in the Strait.

10. In the event of such a crisis, Saudi Arabia’s spare production capacity would obviously be useless. Therefore the International Energy Agency (IEA) would have to shoulder the burden of dealing with the aftermath alone. Balancing the market would be even more challenging as 85% of the oil and 50% of the LNG being shipped though Hormuz is bound eastward, where key non‐IEA members such as China, India, Indonesia and Thailand may not have built up sufficient strategic petroleum stocks. In a statement early this year, the IEA did reaffirm its preparedness to respond to any major oil supply disruption. It remains to be seen what this response would entail and what effect it would have in a market gripped by panic.

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Economic Commentary Volume 7 No 12 ‐ December 2012


MENA Natural Gas Endowment Is Likely To Be Much Greater Than Commonly Assumed

This research‐in‐progress paper has been prepared by Ali Aissaoui, Senior Consultant at APICORP. The findings will be debated at the 4

th AGA Symposium (Algiers, 18‐19 February 2013). The views expressed are those of the author only.

1. Recent assessments of natural gas reserves and resources outside the Middle East and North Africa (MENA) have greatly expanded the world’s potential resource base.1 Already, large conventional discoveries offshore East Africa, together with unconventional gas developments in North America, have transformed the energy landscape and outlook. This build‐up has somewhat turned into a hype‐driven rush for business opportunities. Feeding the hype, prominent Middle Eastern companies have been reported as either seeking to export LNG from the US or contemplating moving some of their petrochemical investment there.2 Except Iran, which has managed in recent years to add large volumes to its huge reserves, there is a tendency to discount MENA natural gas prospects. This may stem from the current perception of scarcity in parts of the region. Indeed an increasing number of apparently well‐endowed countries have been unable to balance their domestic natural gas market, shifting supply to oil products or filling the gap with imports, both at a very high opportunity cost.

2. Few studies have sought to shed light on this “MENA gas puzzle”.3 Unfortunately, they could not offer any deep insight into the region’s gas reserves and resources. Others have either ignored the issue or simply overlooked the most significant part of the region. The latter case is exemplified by current assessments of world shale basins ‐ with or without resource estimate – which have tended to exclude the Middle East – and Russia for that matter.4 It is as if the source rocks of these omitted world’s richest hydrocarbon regions were not rich enough compared to those of North America, Western Europe, China, India, Australia, Brazil or even Argentina.

3. Our commentary seeks to contribute to filling that research gap. More specifically, it aims to offer an empirical analysis supporting the view that, notwithstanding the present critical supply situation, MENA natural gas endowment is likely to be much greater than commonly assumed. The analysis is in two parts. The first draws on BP Statistical Review of World Energy (BP) to evaluate the extent MENA natural gas reserves are being depleted and in what way the resulting supply pattern is evolving. The second builds on the latest assessment by the US Geological Survey (USGS) to ascertain MENA natural gas

1 MENA is defined to include the Arab world and Iran. Despite progress to demarcate borders and delineate oil deposits, Sudan is kept inconsequentially aggregated with South Sudan. 2 The former involves Qatar Petroleum partnering with Exxon Mobil and seeking permission from US authorities to export LNG. The latter is inferred from “SABIC eyes U.S. investments on back of shale gas boom – CEO”, Reuters, JUBAIL, Saudi Arabia, Nov. 12, 2012. 3 Fattouh B. and Stern J. (Ed.) (2011), “Natural Gas Markets in the Middle East and North Africa”, Oxford Institute for Energy Studies. 4 US‐EIA (2011), “World Shale Gas Resources: An Initial Assessment of 14 Regions outside the United States”.

endowment.5 Because of the selective and limited data made available by USGS so far, the second part should be taken as research in progress.

Assessment Framework, Definitions and Data

4. The first part of the analysis is based on proved reserve and production series as reported in BP2012. The accepted definition for proved reserve 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 the concept of “reserve growth”, which is defined next.

5. The second part of the analysis builds on the latest assessment by the US Geological Survey (USGS2012) of both reserve growth and undiscovered conventional resources. Accordingly, our analytical framework and supporting data are depicted in Figure 1. Reserve growth is defined in the USGS2012 as “the estimated increases in quantities […] that have the potential to be added to remaining reserves in discovered accumulations through extension, revision, improved recovery efficiency, and additions of new pools or reservoirs”. Undiscovered resources are defined as the “recoverable resources that have the potential to be added to reserves within a time frame of 30 years”.

Figure 1: Analytical Framework and Supporting Data

Cumulative production

Undiscovered volumes in 26 provinces

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6. We have split undiscovered resources into three aggregates: a) those assessed by USGS2012 in 26 provinces; b) those inferred from distribution models in 50‐odd provinces (the 50‐odd number is explained later in the relevant section); and c) further reserve growth resulting from an extension of USGS original concept. Summing up already produced volumes, remaining reserves, potential reserve growth and undiscovered resources (those estimated in 26 provinces) results into USGS‐based natural gas endowment. However, as elaborated in later sections, our inference of undiscovered gas resources in the non‐assessed provinces, and the extension of reserve growth to the volumes of both discovered and yet to be discovered reserves results into a higher endowment.

5 http://energy.usgs.gov/OilGas.aspx (last visited Nov. 30, 2012).

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Reserves Depletion and Supply Pattern

7. At the start of 2012 MENA proved natural gas reserves were estimated at 88 trillion cubic meters (tcm), representing 42% of the world’s total. The state of these reserves and their depletion are examined by using two simple 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 8. The reserve replacement ratio (RRR) measures the amount of proved natural gas reserves added during the years relative to the amount produced. Added reserves include revisions of previous estimates, improved recovery, extensions and new discoveries. Figure 2 shows long‐running average RRR for MENA and the world, approximated with 5‐year moving averages. 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 15.7x (1,570%) in 1991 came in the wake of significant upward revisions associated with the reflation of crude oil reserves in Saudi Arabia, the UAE and Kuwait during the second half of the 1980s. This first peak was topped by Qatar’s claim of the North Field and Iran’s assertion of South Pars. The second peak of 13.1x (1,310%) in 2002 resulted from subsequent reserve revisions of these two giant gas fields. Since then MENA RRR has been declining abruptly. The downward trend would have been even more marked in the absence of Iran’s significant additions to reserves in 2010. As a result the latest MENA 5‐year average RRR stood at about 2.5x (250%). Such trends may give the alarming impression that, except for Iran’s recent additions, 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.

Figure 2: MENA and World RRR – Long Running Averages

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9. We should expect the above aggregates to conceal considerable differences across countries. Table 1 shows that in recent years Iraq ‐ by far, Iran, Bahrain, Saudi Arabia, Yemen and Libya whose latest 5‐year average RRRs are higher than 1x (100%), have managed to replace a large portion of their extracted reserves, while Egypt, Kuwait, Algeria have struggled to keep pace with production. In contrast, Syria, Oman, Tunisia, Qatar and the UAE have failed to keep pace with production. In

the latter group, while the case of Qatar should obviously be considered in connection with the ongoing moratorium on further developments of the North Field, the situation appears unmistakably critical.

Table 1: 30‐yr, 10‐yr and 5‐yr RRR Moving Averages

Last 30‐yr Last 10‐yr Last 5‐yr Iraq 23.32 22.51 45.23Iran 14.22 5.58 9.60Bahrain ‐0.15 1.63 4.00Saudi Arabia 4.62 2.34 2.66Yemen .. .. 2.05Libya 3.86 2.50 1.05Egypt 5.47 1.91 0.48Kuwait 2.82 1.67 0.07Algeria 0.02 ‐0.02 0.00Syria 13.22 0.63 ‐0.20Oman 8.49 0.66 ‐0.25Tunisia .. 2.36 ‐0.78Qatar 45.04 36.84 ‐1.07UAE 8.52 0.21 ‐1.40MENA 8.34 4.86 2.54

APICORP Research using BP Statistical Review

Avrage RRR

Reserve Life 10. The ratio of reserve to production (R/P) can provide a practical measure of reserve life. Applied to the most recent annual production (2011), it amounts to 131 years for the region as a whole compared to 64 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 6.9% a year, which corresponds to the last 10‐year average, future volumes from remaining reserves would last 33 years. This is just above the conventional 30‐year time horizon for strategic planning in the field of exploration and development (E&D).

Figure 3: Semi‐dynamic Reserve Life of MENA Gas Reserves

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11. As with the RRR metric, the R/P ratio is subject to significant variations across countries. Figure 4 shows 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 the UAE, Iran, Kuwait, Algeria and Egypt are all higher than 30 years. However, apart from Saudi Arabia, which is at the limit of this critical time horizon, all other countries are beneath it, with Bahrain, Syria and Tunisia facing a serious situation.



Figure 4: Countries’ Dynamic Reserve Life

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Supply Pattern 12. 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 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 different countries are far from or near that threshold.

13. This is illustrated in Figure 5 for MENA as a whole. The figure depicts the pace at which the region has been progressing, decade after decade since 1970, towards the OST dashed line. Not being on the line yet means that the pattern of gas use (domestic consumption and export), by under‐reflecting the structure of petroleum reserves, is sub‐optimal. In other words, natural gas has still some leeway for penetration in the energy balance. Conversely, being beyond the line indicates that natural gas is being used unsustainably.

Figure 5: MENA Gas Supply Path Pattern

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14. The 2011 cross section in Figure 6 confirms the above aggregate trend. Progressing towards the OST line should not worrisome; 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, Yemen the UAE, Tunisia, Saudi Arabia, Kuwait, Libya and Bahrain. While the case of Iraq underscores the urgent need to limit gas flaring, that of Bahrain suggests that the country is using more gas than it could possibly afford from domestic sources.

Figure 6: MENA Countries Distances to OST

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15. But our OST metric can be seen as a mechanistic interpretation of reality, which needs to be balanced with market and economic conditions. 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.

Undiscovered Resources and Reserve Growth

16. So far we have focused our analysis on proved reserves. We now turn to undiscovered resources and reserve growth. As noted earlier (Figure 1), USGS focused on 26 geological provinces, which have a history of E&D or those deemed to be highly prospective. Despite the fact that USGS2012 has covered larger MENA areas than did USGS2000, the number of geological provinces assessed decreased from 33 in USGS2000 to 26 in USGS2012, out of an original portfolio of 88 provinces. The seven apparently missing provinces must have changed status in the meantime, from resources to reserves as a result of drilling. Conversely, a few provinces covered in USGS2012, such as the Nile Delta Basin and the Levant Basin in the Eastern Mediterranean, were not covered in USGS2000. Complicating further the arithmetic of provinces is the fact that USGS evaluations are done by assessment units (AUs), which can overlap into more than one province as is the case in the Arabian Peninsula and Zagros Fold Belt. Hence our earlier mention of 50‐odd non‐assessed provinces.

17. Undiscovered conventional petroleum resources within MENA region have been reported by USGS2012 as follows: 6

Region 2 (26 assessed provinces), the Middle East and North Africa, includes the Zagros Fold Belt of Iran, Arabian Peninsula, southern Turkey, and geologic provinces of North Africa from Egypt to Morocco. This region is estimated to contain a mean of 111 BBO, about 60 percent (65 BBO) of which is estimated to be in the Zagros and Mesopotamian provinces. This region is estimated to contain a conventional gas resource mean of 941 TCFG [26.6 tcm], about 60 percent (566 TCFG) of which is estimated to be in the Zagros Fold Belt and the offshore areas of the Red Sea Basin, Levantine Basin, and Nile Delta provinces.

6 USGS (2012), “An Estimate of Undiscovered Conventional Oil and Gas Resources of the World”, World Petroleum Resources Project. Fact Sheet 3028, March 2012.



MENA undiscovered natural gas resources of 26.6 bcm in 26 provinces are detailed in Table 2. As the analysis of USGS2012 assessment is still in progress, there are some inconsistencies between different released fact sheets, which we have tried to resolve (added seventh row in Table 2).

Table 2: USGS2012 MENA Undiscovered NG Resources

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1. Arabian Peninsula and Zagros Fold Belt 23 7 19 336.2 9.5

2. Red Sea Basin 5 1 1 112.3 3.2

3. Nile Delta Basin Province, Eastern Mediterranean a 4 1 1 223.2 6.3

4. Levant Basin Province, Eastern Mediterranean 3 1 1 122.4 3.5

5. Hamra Basin, Libya 4 1 1 4.7 0.1

6. Libya and Tunisia 4 3 2 38.5 1.1

7. Assumed unreported AUs b .. .. 1 103.7 2.9

8. Total MENA region 43 14 26 941.0 26.6a Two AUs out of 4 have not been quantitatively assessed.b Assumed to get the same total as in USGS world summary.

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18. Our next step is to try and estimate natural gas volumes in the 50‐odd non‐assessed provinces. Obviously, any such an attempt raises serious methodological challenges. In contrast to USGS analysts, who base their assessment of undiscovered resources on geological insight, we have no choice but to infer these volumes from size distribution models. As highlighted in Box 1, the most widely used are constant shape distribution models (log‐normal and fractal or power‐law), with tend to either underestimate or overestimate endowments. An alternative model is the Variable Shape Distribution (VSD). Contrary to the other models, VSD does not presume any form of the distribution function, but allows actual data to determine the relationship.

19. VSD has been applied by Prof. Roberto F Aguilera to predict endowment in different regions around the world using USGS’s assessments.

7 MENA findings are shown in Figure 7. They are based on data for the 88 provinces that formed USGS2000’s original portfolio. The black diamonds represents endowments before reserve growth in 33 assessed provinces as published by USGS2000. These endowments total 93 tcm (54 tcm of known reserves plus 39 tcm of undiscovered resources estimated at that time). The solid blue continuous line is the corresponding VSD regression fit with a correlation coefficient (R

2) of 0.98. The green triangles show VSD predictions of the endowment for all 88 provinces with a total volume of 112 tcm. The difference of 19 tcm between VSD‐based and USGS‐based endowments – before growing reserves ‐ corresponds to the undiscovered volume in the 55 non‐estimated provinces. In the absence of updated VSD simulations using USGS2012 data, we have elected to accredit this volume to the current 50‐odd non‐assessed provinces on the assumption that it will likely be invariant to USGS estimates as long as the number of non‐assessed provinces remains virtually unchanged.

Figure 7: Normalized conventional Gas Endowment (size of provinces) vs. Cumulative Number of Provinces for MENA

Source : Aguilera (2012) [volumes converted to tcm from source]

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20. USGS2012’s potential additions to conventional natural gas resources from reserve growth have been estimated to 8.2 tcm for the US and 40.5 tcm for the non‐US world. The resulting percent increase from known recoverable (cumulative production plus remaining reserves) volumes is 25% for the US and 16% for non‐US world, both much lower than the figures

7 Aguilera, Roberto F., and Aguilera, Roberto (2012), "Indexation and Normalization Modeling of Natural Gas Endowment”, Mathematical Geosciences 44 (3): 257‐282.

Box 1: Size Distribution Models in a Nutshell

Conventional Constant Shape Distribution (CSD) Models In lognormal distribution models, modes shift towards undiscovered, smaller‐size accumulations. A lower bound tends to drive lognormal models towards power law (fractal) models (Figure A). The former models tend to underestimate resources the latter to overestimate them.

Figure A

In a fractal distribution model data are fit below the limit of economic perceptibility (black spots in Figure B) before being extrapolated to undiscovered, smaller‐size accumulations.

Figure B

Novel Variable Shape Distribution (VSD) Model VSD does not presume any form of the distribution function, but allows actual data to determine the relationship. As illustrated in Figure 7, VSD requires a numerical solution to a nonlinear least square regression model:

Min {Vx, ap, Vs, Ψ, S} ∑ (Vi‐Ṽi)2

i=1,n Subject to constraints on 5 parameters: Vx: Maximum volume given by the Pareto straight line; ap : Slope (~ fractal slope); Vs: Approximate deviation volume; Ψ: Separation ratio; S: Severity exponent (steepness).



released by USGS2000. In the absence of data for MENA, we conservatively apply the mid‐point average of 20%. It is worth noting in this regard that USGS staff members estimated in the mid‐2000s the rate of reserve growth for the region at about 60%.8 However, this rate might have been inflated in a context of significant upward revisions of both South Pars and North Field (see section on RRR, paragraph 8). Furthermore, in contrast to past estimates, which were based on analyses and extrapolations of historical patterns, the USGS2012 method now relies on detailed analyses of engineering geology practices in producing fields, raising the issue of uncertainties arising from the availability and reliability of data.9 Therefore, it is better to be on the conservative side.

21. A further justification for adopting a conservative rate of reserve growth is the idea of extending the rate to undiscovered volumes. This idea was once contemplated by USGS on the plausible assumption that increases in recovery factors would ultimately benefit both discovered and yet to be discovered fields. In such a case, the expectation is that recovery factors in the non‐assessed MENA provinces would be much lesser than in the 26 assessed ones.

22. Applying the rate of reserve growth of 20% to both known and undiscovered volumes leads to a MENA natural gas endowment of 173 bcm (Table 2 – Total in Column 7). By construction, this is higher than the USGS‐based endowment of 144 tcm (Table 3 – Total in Column 4).

Table 3: Allocations of Endowment Aggregates

1.

Cumulative

production

from origin

to 2011

2.

Proven

reserves

as of 1st

Jan 2012

3.

USGS2012

estimates of

undiscovered

resources 1

4.

USGS2012

with growth

of known

reserves

5.

Weighted

average of

1,2, and 3

6.

Inferred

resources in

non‐assessed

provinces

7.

Endowment

after growth of

reserves and

resources

8.

Undiscovered

resources and

volume

growth(tcm) (tcm) (tcm) (tcm) (tcm) (tcm) (tcm) (tcm)

Iran 2.035 33.100 5.921 48.083 13.038 6.4 57.0 21.8

Saudi Arabia 1.505 8.200 12.684 24.330 5.600 2.8 30.2 20.5Qatar 0.961 25.000 0.775 31.928 8.943 4.4 37.4 11.4

Iraq 0.070 3.600 2.246 6.650 1.609 0.8 8.0 4.4UAE 1.023 6.100 0.821 9.369 2.682 1.3 11.1 4.0

Algeria 2.026 4.500 0.904 8.736 2.664 1.3 10.5 4.0Egypt 0.705 2.200 0.366 3.852 1.147 0.6 4.6 1.7

Oman 0.297 0.900 0.617 2.053 0.551 0.3 2.5 1.3Libya 0.272 1.500 0.389 2.515 0.701 0.3 3.0 1.2

Kuwait 0.3 1.8 0.1 2.644 0.774 0.4 3.1 1.0Yemen 0.0 0.5 0.4 1.073 0.260 0.1 1.3 0.8

Bahrain 0.3 0.3 0.3 1.002 0.290 0.1 1.2 0.7Lebanon 0.0 0.2 0.3 0.540 0.117 0.1 0.7 0.5

Sudan 0.0 0.1 0.3 0.395 0.077 0.0 0.5 0.4Syria 0.1 0.3 0.1 0.582 0.169 0.1 0.7 0.3

Eritrea 0.0 0.0 0.2 0.206 0.034 0.0 0.3 0.3Tunisia 0.1 0.1 0.1 0.281 0.075 0.0 0.4 0.2

Jordan 0.0 0.0 0.0 0.052 0.009 0.0 0.1 0.1Morocco 0.0 0.1 0.0 0.062 0.017 0.0 0.1 0.0

Total MENA 9.7 88.4 26.6 144.4 38.755 19.0 172.5 74.4

APICORP using BP Statistical Review of World Energy (June 2012), USGS (2012) and Aguilera (2012)

1 Country distribution inferred from USGS2000

23. Country allocations of these findings are usually done pro rata of proved reserves. However, this would give large reserve holders with few leftover provinces to explore, such as Qatar, an excessive share. Instead, the most plausible results have been obtained by placing decreasing weights on cumulative production, proved reserves and undiscovered resources in a proportion of 3/6, 2/6, 1/6 respectively. Subtracting known reserves leads to undiscovered volumes, which hint at substantial E&D potential in Iran, Saudi Arabia, Qatar, Iraq, the UAE and Algeria. To a lesser extent, opportunities appear to be also present in Egypt, Oman and Libya.

8 Klett, Timothy R. et al. (2005), “An Evaluation of the U.S. Geological Survey World Petroleum Assessment 2000”, AAPG Bulletin, The American Association of Petroleum Geologists, 6 April. 9 Klett, Timothy R. et al. (2011), “New U.S. Geological Survey Method for the Assessment of Reserve Growth”, USGS.

24. Finally, what about unconventional natural gas resources? USGS2012 team has made it clear that such resources cannot be inferred from any of their conventional resource estimates, but has indicated that they are being assessed as part of a separate study. According to Thomas Ahlbrandt, who led USGS2000 and was its MENA coordinator, the previous assessment included the Qalibah formation, which consists of Qusaiba and Sharawra, both largely unconventional (shale). Accordingly, unconventional natural gas resources can be truly significant. Thomas 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.” The reason, he explains, is that “U.S source rocks are modest compared to the Silurian, Jurassic, Cretaceous and Tertiary source rocks in the region.” Indeed, “the Silurian is a huge unconventional Basin Center Gas Accumulations (BCGA) target in Algeria, Libya, Saudi Arabia, Iraq and Jordan.” That Iran and Saudi Arabia emerge in our assessment as the largest prospect for undiscovered resources and volume growth of conventional natural gas can be strengthened by the prospect for unconventional as well. In Thomas’ 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.”

10

Conclusions

25. This commentary has drawn on the latest BP’s Statistical Review of World Energy and USGS’s World Petroleum Resources Assessment to provide an updated empirical analysis of MENA conventional natural gas endowment.

26. Our findings confirm and extend our previous results showing that on aggregate MENA proved reserves are substantial and their combined dynamic life is a little beyond the traditional 30‐year strategic planning horizon for E&D. However, reserve depletion in more than half our large sample of countries has critically neared ‐ if not already reached ‐ the point that warrants drastic actions to curb demand and support a supply response. The opportunities for the latter will be driven by a vast potential for reserve expansion. On a country‐by‐country basis the potential appears to be the greatest in Iran, Saudi Arabia and Qatar, followed by Iraq, the UAE and Algeria. Prospects also seem favorable in Egypt, Oman and Libya. As the opportunities available will be increased by unconventional gas, they will entail significant challenges. Confronting the region’s natural gas paradox ‐ a paradox of scarcity amidst plenty – requires both a demand and supply response. As far as the supply side is concerned, MENA policy makers need to rethink critically their E&D policies and the corresponding economic incentives.

10 Email correspondence with the author dated 9 December 2010 and 28 November 2012. For further insight 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 Convention, New Orleans 11‐14 April.

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