The future of IPPs in the GCC: New policies for a growing and evolving electricity market

In recent years, countries in the GCC have increasingly turned to independent power projects (IPPs) as alternatives to government-financed power plants. But the IPP model being used in the region, while serving to augment and diversify investment resources, presents long-term risks. Changes in the way that IPPs are structured can preserve the benefits of the IPP model while substantially reducing these risks.

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The future of IPPs in the GCC New policies for a growing and evolving electricity market

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Abu Dhabi George Sarraf Partner +971-2-699-2400 george.sarraf @strategyand.pwc.com Beirut Georges Chehade Partner +961-1-985-655 georges.chehade @strategyand.pwc.com

Dubai Andrew Horncastle Partner +971-4-390-0260 andrew.horncastle @strategyand.pwc.com David Branson Executive Advisor +971-4-390-0260 david.branson @strategyand.pwc.com James Thomas Principal +971-4-390-0260 james.thomas @strategyand.pwc.com Christopher Decker Senior Associate +971-4-390-0260 christopher.decker @strategyand.pwc.com

Strategy& is a global team of practical strategists committed to helping you seize essential advantage. We do that by working alongside you to solve your toughest problems and helping you capture your greatest opportunities. These are complex and high-stakes undertakings — often game-changing transformations. We bring 100 years of strategy consulting experience and the unrivaled industry and functional capabilities of the PwC network to the task. Whether you’re charting your corporate strategy, transforming a function or business unit, or building critical capabilities, we’ll help you create the value you’re looking for with speed, confidence, and impact. We are a member of the PwC network of firms in 157 countries with more than 195,000 people committed to delivering quality in assurance, tax, and advisory services. Tell us what matters to you and find out more by visiting us at strategyand.pwc.com/me.

This report was originally published by Booz & Company in 2010.

EXECUTIVE SUMMARY

In recent years, countries in the Gulf Cooperation Council (GCC) have increasingly turned to independent power projects (IPPs) and independent water and power projects (IWPPs) as alternatives to government-financed power and cogeneration plants. By shifting investment in power generation and water desalination to the private sector, these countries have been able to redirect public resources to other development priorities and to engage private-sector stakeholders in the challenge of supplying the region’s growing power and water needs. The IPP model being used in the region, while serving to augment and diversify investment resources, presents long-term risks: The model may prove costly to governments if growth in power demand slows, and it may prove unduly constrictive if power markets liberalize. Also, the current bidding process has skewed development in favor of base-load plants, which could ultimately leave system planners struggling to meet daily and seasonal fluctuations in demand. Changes in the way that IPPs are structured can preserve the benefits of the IPP model while substantially reducing these long-term risks. These changes include developing an “IPP liability indicator” to constantly measure the government’s outstanding liabilities, encouraging offtake sharing with industrial users, tendering IPPs to ensure a diverse range of generation assets, and adding government buyout clauses to prevent IPPs from becoming stranded assets in a future liberalized electricity market.

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KEY HIGHLIGHTS • IPPs have almost entirely displaced traditional public power plants as sources for new electricity generation in the GCC. • Rational choices made at the case-by-case project level have left the IPP model vulnerable to long-term aggregate risks, such as accumulated offtaker liabilities, a potential shortfall of plants capable of providing mid- and peak-load service, and the postponement of fully liberalized electricity markets. • Several changes to the existing model would make IPPs more adaptable to an evolving market while preserving the ability of IPP developers to earn a competitive return on their investment.

THE TRIUMPH OF THE IPP MODEL

IPPs are a relatively new phenomenon in the GCC. Up until the mid-1990s, power plants in the region were exclusively financed and developed by governments and governmentbacked corporations. Then, in 1996, the 270-megawatt Al-Manah power plant in Batinah, Oman, became the first power plant to be financed, built, and operated by the private sector. Six years later, the region’s first operating IWPP, the 710-megawatt Taweelah A2, opened in Abu Dhabi. Since those initial forays, IPPs and IWPPs have proliferated across the region, expanding to Qatar, Bahrain, Saudi Arabia, and recently Kuwait

and Dubai. Across the GCC, more than two dozen IPPs and IWPPs are now in operation, with a combined installed capacity of 20 gigawatts, in addition to the many captive power plants dedicated to serving specific industrial users. Current expansion plans will more than double the region’s IPP and IWPP capacity over the next five years, bringing the privately developed share of aggregate electricity generation to about 34 percent (see Exhibit 1). Under the current IPP model, the government or its designee identifies the need for a new plant, specifies its characteristics, and invites privatesector developers to compete for the right to finance, build, and operate it. Once completed, the plant remains in private hands, but its output—the actual electricity and water produced—is sold back to the government offtaker through a power purchase agreement (PPA, or PWPA in

Exhibit 1 IPPs and IWPPs Are Making Inroads in the GCC

GCC INSTALLED POWER CAPACITY (NON-CAPTIVE POWER IN GIGAWATTS) 145 24 (16%) Unassigned

94 22 (23%)

49 (34%)

IPP/IWPP

72 (77%)

72 (50%)

GovernmentFunded

2009

2015E

Source: Booz & Company

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the case of an IWPP) at a predefined price. Such agreements, which run for 20 to 25 years, provide for a capacity payment and an energy payment. The capacity payment is designed to cover fixed costs: development costs, capital investments, fixed operations and maintenance (O&M) expenses, and the cost of capital. The energy payment covers fuel costs and variable O&M costs. In cases where the offtaker provides the fuel for the plant, the energy payment covers only variable O&M costs. Within this general framework, GCC countries vary in certain details. Countries permit different levels of private ownership, provide different levels of guarantees, and impose different rules for future share transfers, public offerings, and termination conditions. Nonetheless, the basic IPP model is consistent across the region: The amount of power to be sold is stipulated in the PPA at a fixed price, the PPA is guaranteed by a creditworthy offtaker backed by the government, and the price of fuel is fixed by contract. The model eliminates market and fuel risk for the IPP developer, and the remaining risk consists of difficulties the developer might encounter with financing, construction, and operation. This modest risk profile permits IPP developers to use limited-recourse, high-leverage project financing schemes, with debt ratios averaging 75 percent and reaching as high as 85 percent. Consequently, IPPs have been exposed to the global credit crunch; although there have been recent adjustments to financing terms, they have not fundamentally stopped IPP growth (see “Key Changes in Financing Terms”).

Key Changes in Financing Terms The global credit crunch has caused a number of important changes in IPPs’ and IWPPs’ financing terms: • Shorter repayment schedules • Increased premium over LIBOR • Introduction of bridge loans, as well as soft and hard mini perm loans • Lower debt-to-equity ratios • Increasing equity share of governments • Growing importance of export credit agencies • Limits on financing amount by a single bank • Regional and local banks stepping into the funding gap

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The reason IPPs have almost entirely displaced the traditional public power plants for new generation stems from the operating model that IPPs employ and from several distinct advantages it offers to governments: Amortization of public expenditures: The GCC’s rapidly growing economies and populations require enormous investment in infrastructure and other public goods. IPPs allow governments to install the power capacity they need without large front-end public investments. By amortizing the investment expense

over a 25-year period through capacity payments, governments free up funds to help pay for other development priorities. Competitive cost of power: IPP bidders are evaluated on the basis of a levelized electricity cost (LEC)—and levelized water cost for IWPPs— which incorporates all of the fixed and variable charges a developer proposes to recover into a single price per kilowatt-hour or cubic-meter. LEC bids reflect each developer’s particular mix of project solutions: technical designs and specifications,

choice of technology, types and terms of procurement and construction subcontracts, operating processes, and expected financing costs. Since variations in these factors often yield a broad range of prices, with LEC spreads of as much as 40 percent between the highest and lowest bids, this process encourages developers to be creative and aggressive in streamlining project cost structures. Although cost comparisons with government-funded plants are inherently imprecise, IPP prices appear to be competitive, despite higher financing costs (see Exhibit 2).

Exhibit 2 IPPs Are Generally Competitive with Government-Funded Plants
COMPONENTS OF POWER COST (ILLUSTRATIVE) IPP Power Plant (build, own, operate) Cost/ kWh DIFFERENCES IN COST COMPONENTS: IPPS VS. GOVERNMENT-FUNDED PLANTS Fuel IPPs tend to control their heat rate degradation better. IPPs show slight advantages as a result of lower manpower, more qualified staff, and better procurement practices, which are partially offset by lower salaries in government-funded plants. IPPs have tighter control over capital expenditures, with specifications designed to serve the life cycle of the IPP . Comparisons are often difficult due to the increased cost components of IPP tender packages (e.g., jetty and transmission substations). IPPs have higher financing costs, but benchmarking government-funded plants is difficult. Indirect benefits to the economy are typically not factored into analyses. In the case of an eventual sale, a plant’s terminal value would lower the costs of the IPP .

O&M

Fuel

O&M

Depreciation

WACC

Total

Depreciation

Government-Funded Power Plant Cost/ kWh

?

WACC (weighted average cost of capital)

Other

Fuel

O&M

Depreciation

WACC

Total

Source: Booz & Company

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Predictable timing and often faster execution: In a region coping with rapid increases in power demand, delays and unpredictability in bringing new plants online can be costly on many levels. Once the central utility decides to procure a power plant on an IPP basis, the process from tendering through to commissioning, even with the additional financing steps required, is predictable and often shorter than the process used for government-funded projects. The advantage stems from the discipline of IPP developers in bidding, financing, designing, building, and commis-

sioning plants, and from their cost incentives to expedite construction processes and begin producing power as quickly as possible. The IPP development process is predictable in its timing and results, in contrast to the funding delays, design changes, and overlapping authority that often beset government-funded projects. Establishment of performance benchmarks: In markets long dominated by state utilities, it can be difficult to identify areas in which existing plants are underperforming. IPPs provide operational and financial benchmarks

that can raise the game for all power plants, especially those operating in identical environments. Promotion of a favorable business environment: The impact of IPPs on the overall business environment extends beyond stimulating efficiency improvements in the broader power sector. IPPs also create private-sector employment opportunities and engage an array of stakeholders—local and international banks, investors, and export credit agencies—whose health and vitality are critical to the region’s continued growth.

IPPs provide operational and financial benchmarks that can raise the game for all power plants.

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THE PITFALLS OF THE IPP MODEL

case-by-case project level can lead to unwanted consequences at the sector level. As IPPs become more familiar in the region, policymakers need to be conscious of the potential limits to the advantages they provide. Three of these limits are of particular concern. The first and most obvious limit is inherent in the practice of amortizing present investment. As indicated in Exhibit 3, GCC nations are tying up increasing shares of GDP in explicit

The fundamental risk of the IPP model stems not from individual projects but from the long-term aggregate effect of applying the model exclusively. Rational choices at the

and implicit IPP/IWPP obligations. This is not necessarily a bad thing if governments use the immediate savings to create growth in national wealth that exceeds the accumulating liabilities. However, accumulating liabilities have a way of taking public institutions by surprise. Just as pension obligations undertaken blithely in times of growth can become heavy burdens when they fall due in times of retrenchment, the power purchase commitments made in today’s growth

Exhibit 3 GCC Governments’ IPP/IWPP Commitments Are Accumulating
OUTSTANDING IPP/IWPP LIABILITIES (% OF GDP) 2.7

2.1 1.7

1.0 0.8 0.4

1.2 0.8 0.3 0.9 2009 2015 0.2

0.0 UAE Qatar

Kuwait

Saudi Arabia

Bahrain

Oman

Source: CIA World Factbook; Booz & Company analysis

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period could prove onerous to a future economy that may find itself with an abundance of capacity. In the long run, these accumulating commitments can affect not only the cost of capital required by IPP developers and their lenders, but also the credit ratings of the offtakers themselves. A second long-term risk concerns the fact that IPPs are biased toward providing base-load power, which could ultimately leave system planners struggling to meet daily and seasonal fluctuations in demand. A power system requires a diverse portfolio of generation technologies in order to serve the variable electricity needs of a population efficiently. The system needs plants that are able to run virtually full-time, at relatively low

cost, to serve base-load demand. It also needs plants that are able to start and stop on short notice without loss of efficiency, albeit at relatively high cost, to serve peak loads. As a rule, the plants that run efficiently nonstop are substantially more expensive to build, but much cheaper to operate, than the plants that run efficiently for short periods. Base-load plants, therefore, have a high fixed cost but a low variable cost compared to peakload plants. These cost and operating differences reflect the different technologies and fuels employed in the plant. Finding the most efficient balance of these technologies for a given power system is one of the main responsibilities of system planners. For reasons dis-

cussed in the Appendix (see page 12), this task requires trade-offs between fixed and variable costs. The dominant method of selecting IPP developers through LEC-based bids, however, blurs these trade-offs. Because average energy cost declines as the use of a unit increases, LECbased bids will almost always favor an IPP that is committed to running at full capacity. That is why IPP tenders are biased toward base-load operation, and indeed most IPPs commissioned in the past decade have ended up being operated as base-load plants. This bias toward base load for IPPs imposes both short- and long-term costs. It tends to force existing incumbent base-load plants into

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mid-load territory, where they operate less efficiently on a marginal basis and are far less efficient from the perspective of overall system design. By adding IPP units to serve base load alone, system planners will find themselves over time with an unbalanced system that isn’t as responsive as it could be to daily and seasonal demand fluctuations. There is also an opportunity cost to this base-load bias. The advantages

of IPPs over incumbent plants are likely to be far greater in the mid-load and peak ranges of operation than in the base-load range. The start-stop operation of mid-load and peak-load plants offers greater potential gains from management efficiency than the steady-state operation of baseload plants. Although best-practice management methods may produce efficiency gains of 2 to 3 percent for base-load plants, they can offer gains as high as 30 percent for mid- and

peak-load plants. By concentrating IPP awards in the base-load category, the GCC is forgoing much of the economic gain that IPPs could provide. The third risk of IPP dependence is that it can inhibit the natural evolution of the power sector toward increased liberalization. Virtually every country in the GCC entertains the vision of a liberalized power market at some point in the future. As each market moves in that direc-

Best-practice management methods can offer gains as high as 30 percent for mid- and peak-load plants.

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tion, the single national wholesale buyer of today will likely give way to multiple wholesale buyers, governments will reform their fuel and power subsidies, and market prices will increasingly guide the short- and long-term deployment of resources. However, if the current trajectory of IPP investment continues, using the existing model, GCC nations may find within 10 years that a major portion of their generation assets are locked down in long-term PPA contracts. Such a situation would substantially compromise the flexibility of the power system to adapt to market forces. Today’s embrace of

IPPs is regarded as a constructive step along the path toward market liberalization, but it actually could end up impeding the journey. These three long-term risks—accumulating payment obligations, displacement of incumbent base-load units, and constraints on future market design—are interconnected. GCC governments will face unnecessary increases in future payment obligations when IPPs are misaligned with optimal system requirements. Project-byproject efforts to optimize IPP prices contribute to creating that systemic misalignment by ensuring that developers continue to favor base-load

IPPs over other options that would better support system load patterns. This base-load bias in turn causes the portion of system energy produced by IPPs to grow at an even faster rate than the growth in system capacity. If projections hold true and IPPs account for 34 percent of regional capacity by 2015, with virtually all of that capacity serving base load, then IPPs will account for nearly 60 percent of regional energy production. With this much energy production locked into long-term PPAs, the structure of the region’s energy markets will be substantially preordained for the next two decades.

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MAKING THE IPP MODEL LAST

GCC governments can counter and even avoid these long-term drawbacks if ministries, regulators, and public utilities act now to introduce some changes to the IPP model. These changes would be reflected in the regulatory framework and the electricity system plan, as well as in the way IPPs are packaged, tendered, and structured. As a starting point, finance ministries should develop some type of “IPP liability indicator” to calculate the offtaker’s outstanding liabilities as a function of the nation’s GDP. Such a mechanism would allow finance officials to closely monitor their total exposure under alternative scenarios, to define the circumstances under which they will back PPAs with sovereign guarantees, and to

set deliberate boundaries on future liabilities. A government may decide that loose boundaries are appropriate, but it should make that decision consciously and not through inertia. To contain liabilities, GCC authorities should not only allow but encourage IPPs to secure contracts with additional buyers, such as long-term industrial customers. Diversifying a plant’s end-users could reduce the magnitude of governmental obligations to IPPs that might one day become stranded assets. Governments should empower IPPs to sell excess electricity not just to the network but to other industrial users as well by allowing and regulating “wheeling” (see Exhibit 4). Though incumbent operators have been reluctant to allow such arrangements

Exhibit 4 More Buyers, More Flexibility, Fewer Costs
WHEELING ARRANGEMENT

Captive IPP

Primary Offtaker (Industry) Synergies

Pays wheeling charges Sells excess capacity System Operator

Secondary Offtaker (Customer)

Source: Booz & Company

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in the past, the deals could be structured to provide a win-win value proposition. This would enable the IPPs to contribute to the country’s growth and ease the way for market liberalization, while preserving incumbent operators’ existing revenue streams. Locating an IPP next to an industrial plant that shares the offtake also could allow the IPP to achieve cost savings through the sharing of common facilities. With an appropriate portfolio of offtake commitments, an IPP might be able to serve the system’s peak requirements as needed while also capturing the efficiencies of full-time operation. To ensure that the power system operates as efficiently as possible, system planners should shape IPP tenders as components of an integrated system plan. They should consider procuring a diverse range of IPPs not only for base-load service but also for mid-load and peak-load service. In some GCC countries, IPP tenders are specified for particular load categories—a practice that should be emulated throughout the region. As planners clarify their load-service requirements, they also should clarify the relevant price to beat—i.e., the price at which the incumbent government-run generator

could meet a comparably defined load requirement. That would establish a ceiling for acceptable IPP bids. Recognizing that IPPs commissioned today might become stranded assets in a future liberalized market, government offtakers should begin now to build clauses into new IPP contracts that give them the right to acquire the IPP in the future for the unamortized value of the developer’s investment. The offtaker would then have the option of taking ownership of the asset and auctioning it to any interested investor at a price appropriate to the new market. Buyout mechanisms would help assure today’s investors of their expected return, while ensuring that PPA commitments will not preclude a future liberalized market. Government offtakers should also consider renegotiating existing contracts in order to secure similar buyout options for IPPs already in place. Although changes of this kind will be challenging to execute, they would be well worth the effort, as they would make IPPs more adaptable to an evolving market and help integrate IPPs more fully into the overall power strategy of the countries they serve. Also important, governments could implement these changes without limiting their options for future market design or impairing the ability of

IPP developers to earn a competitive return on their investment. These changes—IPP liability indicator, encouraging additional buyers, procuring different IPP loads, and building buyout mechanisms—would help ensure that the current IPP model evolves to meet the challenges of a more open market. At some time in the future, regional electricity markets will likely liberalize, tariffs will cover economic costs, and government will remove itself from the business of overseeing and subsidizing power. At that point, IPPs will play the same role they have filled in liberalized power markets elsewhere—markets in which they invest at their own risk and earn returns that are determined not only by their efficiency as developers and operators, but also by the market itself. Power markets in the region are evolving, and IPPs are assuming too important a role in GCC countries to be treated as anomalous outliers to the power system. Instead, IPPs should be active enablers of market evolution. By making adjustments to the prevailing model, GCC governments will continue to be able to rely on private generation as a source of cost-competitive power and as a liberating alternative to the capitalintensive power projects of the past.

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Appendix: Aligning System Supply and Load Exhibit A uses two charts to depict the primary factors involved in aligning a system’s power supply and its load. It presents an approximate reflection of the technologies, load, and supply in use in the GCC today. Chart 1 displays two lines that portray the characteristics of units in the generation supply portfolio. The downward line, oriented to the right-hand y-axis, indicates the portion of the year during which a given load is required. The shape of this line is determined by the system’s pattern of power demand and assumes that generation units are dispatched in “merit order” of marginal production cost—cheapest first, most expensive last. The upward line, oriented to the left-hand y-axis, indicates the marginal cost of dispatching each unit. The first line is a load-duration curve, and the second is a supply curve. Together, these two curves indicate the cost of operating a particular unit and the duration of that unit’s operation. Chart 2 provides the other main piece of information needed to align supply and load: the average cost per megawatt- hour of the generation designs that can be deployed. This measure includes not only a unit’s marginal cost but also a portion of its fixed cost. The fixed-cost portion depends on how many hours a unit is run; the fewer the hours, the greater the portion assigned to each hour. The plant’s average cost of production climbs as the plant is used less often, and the chart illustrates this relationship. However, because different plant designs have different fixed costs and different marginal costs, each design’s average cost starts at a different point and rises at a different rate. (continues on next page)

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By displaying the three major GCC design options together, Chart 2 indicates the level of use at which each design becomes the most efficient choice. Base-load design is the most efficient choice at capacity factors above 65 percent. Mid-load design is the most efficient choice at capacity factors between approximately 65 and 15 percent. Peak-load design is the most efficient choice at capacity factors less than 15 percent. Applying these capacity-factor break points from Chart 2 to the load curve in Chart 1, we can deduce approximately how the regional supply curve should be constructed for economic efficiency. In this example, the capacity of the generation portfolio should consist of approximately 50 percent baseload design, 30 percent mid-load design, and 20 percent peak-load design. Because of the different load factors applied to each segment of the supply curve, the actual energy produced—the area under the load curve—would be approximately 75 percent for base-load, 23 percent for mid-load, and 3 percent for peak-load service. When base-load design is consistently dispatched to serve mid-load demand, as occurs when incumbent base-load service is displaced by an excess of IPP base-load service, this efficient design is distorted. Rather than reflecting the lowest-cost choices defined in Chart 2 by the lowest of the three curves across the capacity range, the supply curve in that event provides a mix of plant designs that is suboptimal. Costs will rise over time; the greater the displacement, the greater the increase.

Exhibit A Aligning Power Supply and Load

CHART 1 MARGINAL COST & LOAD DURATION Marginal Cost/MWh % of Year 100%

CHART 2 AVERAGE COST OF DESIGN OPTIONS Average Cost/MWh

80% 65% 15% 60% 40% 20% 20% 40% 60% 80% System Capacity 100% 100% 80% 65% 60% 40% Capacity Factor 20% 15% Peak-load design Mid-load design Base-load design

Source: Booz & Company

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Strategy& is a global team of practical strategists committed to helping you seize essential advantage. We do that by working alongside you to solve your toughest problems and helping you capture your greatest opportunities.

These are complex and high-stakes undertakings — often game-changing transformations. We bring 100 years of strategy consulting experience and the unrivaled industry and functional capabilities of the PwC network to the task. Whether you’re charting your

corporate strategy, transforming a function or business unit, or building critical capabilities, we’ll help you create the value you’re looking for with speed, confidence, and impact.

We are a member of the PwC network of firms in 157 countries with more than 195,000 people committed to delivering quality in assurance, tax, and advisory services. Tell us what matters to you and find out more by visiting us at strategyand.pwc.com/me.

This report was originally published by Booz & Company in 2010.

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