As usual during this period of the year, our commentary presents Arab Petroleum Investments Corporation’s (APICORP) main findings of its rolling five-year review of MENA energy investment.(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.

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/B (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/mn BTU in fully liberalized markets with abundant domestic supplies and $12-15/mn BTU in markets relying on imports under traditional long-term contracts.

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

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 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.

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

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).

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 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.

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.

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 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.

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.

Capturing the full scope and scale of the power sector and adjusting for the inclusion of the T&D systems has reshaped the sectoral 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.(5)

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.

MAJOR CHALLENGES

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.

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.

The next challenge is the supply of fuel/feedstock - primarily natural gas to the petrochemical industry and the power sector. Our main findings (6) 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. 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).

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.

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.

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/B 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)

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

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.

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/B. 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.

*Mr Aissaoui is Senior Consultant APICORP. This report is published concurrently in APICORP’s Economic Commentary dated October 2012. The views are those of the author only. Comments and feedback may be sent to: [email protected]

Notes:

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.

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).

4. The biggest MENA holders of combined oil and natural gas reserves in decreasing size are: Iran (50.0 gigatons of oil equivalent), 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).

5. Investments in nuclear and renewables (mostly solar) are implicit and reflected in the average capacity cost in relevant cases. For nuclear, while the 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.

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

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