roundtable dialogue briefings - kapsarc effective incentives, regulations, and infrastructure, the...

KAPSARC Energy Dialogue 2016

Energy Transition and Economic Transformation

November 1− 2, Riyadh, Saudi Arabia

ROUNDTABLE DIALOGUE

BRIEFINGS

For a shorter synopsis of the Roundtable

Dialogue sessions please refer to the

‘DESCRIPTIONS’ document

ROUND TABLE DIALOGUE BRIEFINGS 2

ROUNDTABLE DIALOGUE BRIEFINGS – DAY ONE

Gas and Power Cooperation in the GCC: The Scope for Integrated

Markets

In the face of shared challenges, is cooperation the way forward?

Gulf countries have become a hub for energy development and trade, which has had

a profound effect in driving the economic growth. Energy production and export have

been crucial to the region’s development, yet fiscal dependence on the oil industry

ranges from 60 percent to as high as 80 percent.

In the current context of low oil prices and international efforts to transform the global

energy system towards sustainable production and use, the Gulf region faces new

and increasingly urgent challenges. At present, the area is characterized by high

overall energy demand, high per-capita usage and high waste, in large part because

energy efficiency is particularly low. Looking to the future, the countries face similar

challenges, including:

High dependence on resources that are affected by global market demand.

Rapid population growth, which is likely to lead to increased growth in energy

demand.

A young population – almost one-third of people are under 25 – that is putting

a lot of emphasis on sustainability and also requires strategic plans for job

creation.

Security concerns related to geopolitics.

More recently, the COP21 climate change negotiations have intensified pressure on

the countries to act to mitigate carbon dioxide (CO2) emissions, particularly as they

are not only major producers of fossil fuel but also have some of the highest per-

capita consumption and associated emission levels in the world (IRENA, 2016).

Initial analysis suggests seven areas across which the gas and power sectors in the

Gulf region can benefit from cooperative effort:

Joint market operations.

Coordination in policy and regulation formulation.

Coordination of investment in infrastructure, research and development.

Foreign policy coordination.

Trade regulations.

Standards and quality regulations.

Price-setting practices.

The issues identified above, and many others, must be investigated in order to

understand the full implications of cooperation and ensure informed decision making.


The precedent for cooperation, and motivations to enhance it

Cooperation among the states was formally established in 1981 through the

Cooperation Council for the Arab States of the Gulf (commonly known as the Gulf

Cooperation Council or GCC). The aim of the GCC is to promote and facilitate

multinational cooperation in the region, which now boasts free-trade areas, financial

cities and industrial zones.

The situation described above is driving all GCC countries to search for ways to

diversify their economies. Coordinated effort to tackle these shared challenges at an

aggregate regional level could allow for better distribution of resources, eliminate

inefficiencies and waste, and optimize mutually beneficial opportunities. As the

states share very similar cultures, the same religion and one language, some key

fundamentals for enhanced cooperation are already in place.

Cooperation in power generation

Power generation is very important to economic growth and the welfare of GCC

citizens. With a forecast for increased economic activity and the population growing

quickly – at rates as high as 3.5 percent annually in some countries (IMF, 2015) –

demand for electricity will continue to rise quickly, perhaps even keeping pace with

the annual average rate of 11.2 percent over the past four decades (KAPSARC,

2016). In fact, some estimates suggest that electricity demand in Saudi Arabia could

double by 2030.

Across the GCC, state-owned utility companies have been building new generation

plants, often incorporating the most cost-effective technologies such as combined

cycle gas turbines (CCGT). However, these plants require high upfront investment

and, in some cases, lead to redundancy in the system. Some redundancy is by

design and strategic, but at times it is more reflective of the nature of the region,

particularly in terms of limited coordination and exchange of information. As member

states pursue their own investments, the possibility arises of an oversupply of power

generation capacity across the GCC.

This raises the question of whether a more integrated approach – rather than six

individual systems – could better serve the GCC, both as a region and individually. In

2011, the interconnection grid run by the GCC Interconnection Authority (GCCIA)

became operational, based on estimates that it could help save US$ 1 billion in fuel

cost and another US$ 5 billion in capital investment across the region. To date, it has

been used at only 30 percent of its capacity, suggesting substantial opportunity for

further optimization (KAPSARC, 2015).

Potential also exists for GCC cooperation on fuel imports to run generation plants.

Kuwait has started importing long-haul liquefied natural gas (LNG) while Qatar –

right next door – is flush with natural gas. The UAE, where gas accounts for 87

percent of the power generation capacity (MEES Fri, 26 Aug 2016 - Volume: 59

Issue: 34), is expected to become a net natural gas importer in the near future due to

rising domestic demand, industrialization and economic growth. In the longer term,

all member states face the same factors. At present, with the exception of the

Dolphin pipeline (an example of infrastructure built for intra-regional trade), there is

neither a pipeline infrastructure to move gas nor a mechanism by which to price it.


Overall, price seems to be the main stumbling block to greater cooperation (MEES

Fri, 19 Aug 2016 - Volume: 59 Issue: 33).

An additional concern is that many countries are moving towards renewable energy

sources (RES) in order to mitigate the impact of the shortage of conventional

feedstock. This area is ripe for developing cooperation: it offers many benefit such as

economic diversification, capacity building and upgrading of skills, as well as savings

on both produced fuels and fuel consumption. One issue is that RES generation

plants require substantial investment and capital. In some cases, land is needed in

order to reach a size of significant contribution. A joint GCC project may have

benefits for all.

To assess if opportunity exists for member states to utilize their resources most

efficiently through coordination, policy makers need to compare the benefits and

costs of such integration, in part by exploring key questions. How much excess

capacity exists across the GCC member states? Would member states see

economic benefits from trading electricity using the GCC Interconnection? If the

network were to expand even further, would there be a scenario in which Oman

would not build a power plant but rather depend on the spare capacity of the UAE?

Economic diversification and private sector development

Economic growth in the GCC region is primarily driven by government spending and

large state-owned enterprises (IMF, 2015). If the current trend of a glut in oil supplies

and low prices continues, it could create a concern for GCC revenue from oil and

gas.

The private sector can be the new driver of economic activity and act as the glue that

binds the region together. Indeed, the retail industry has developed interstate

operations that brought the region close in terms of culture aspects.

Private energy companies could also flourish in the context of growing demand as

projected, but corporations are only able to efficiently and effectively capitalize on

synergies gained if they all participate in a uniform market. The region would need a

regulatory scheme based on simplified and integrated commerce-related laws, as

well as a transparent, uniform code. The resulting increased competition would allow

each state to benefit from better prices, more efficient operations and better product

and service offerings.

With effective incentives, regulations, and infrastructure, the private sector can

allocate investments across the region in areas that offer the best potential for

returns. Cooperation could, for example, create opportunities to centralize operations

in areas of low-cost input and transfer the electricity to demand centers (e.g., main

cities). The sates can still play and important role by providing the proper guarantees

and backing. As demonstrated in Dubai, having a credible, credit-worthy backer will

help reduce the cost of borrowing. Indeed, the design of the Dubai auction

succeeded in bringing the price down mainly due to the creditworthiness of the off-

taker (IRENA GCC Report, date).


Can political issues impede cooperation?

In the GCC context, the leading barrier to energy collaboration is how to price the

cost of a barrel of oil equivalent saved. At present, each country has established its

own value and in some cases this value is not monetary. Indeed, determining a

monetary value for factors such as supply security and civil harmony is an

overarching challenge.

Finding ways to clearly identify the components that make up the actual cost and

inherent value of a saved barrel could create a starting point for discussion,

negotiation and eventual cooperation. Carrying out such a dissection would require

in-depth understanding of which entities are invested in the gas and power industry,

their level of involvement and the aspects that are most important (i.e., most

valuable) to them. This raises questions such as whether cooperation can be

achieved as long as stakeholders can agree on ‘the right price’? What is the right

price for each country to pay, whether implicitly or explicitly, in order to gain the

benefit of greater synergy? How will that price correspond to the benefits gained?

It is equally important to understand the structure of the gas and power market, the

motivations behind wanting to reform it and whether any constituency is more

influential than the others. Which entities currently control trade in the region? Why

do proponents of free markets hold that position – e.g., do they feel that cooperation

would lead to free markets? And which entities could control the decisions to either

encourage trade or constrict trade? Is there a risk that cooperation will allow a small

set of constituents to have more or less control? Finally, does control mean more

profits or more security?

Across GCC states, diverse government entities are formally responsible for making

decisions in the power and gas sectors (Table 1), along with different regulatory

authorities and municipalities. Typically, the ministers of finance and foreign affairs

also play important roles, especially when energy-related decisions also have

implications for climate change. The utilities companies, national oil and gas

companies, and independent power producers also have a stake in the decisions

made.

Country Oil and gas Electricity and water Bahrain National Oil and Gas Authority

(NOGA) Electricity and Water Authority (EWA)

Kuwait Supreme Petroleum Council (SPC) Ministry of Petroleum

Ministry of Electricity and Water

Oman Ministry of Oil and Gas (MOG) Ministry of Electricity and Water

Qatar Ministry of Energy and Industry (MEI)

Qatar General Electricity and Water Corporation (Kahramaa)

Saudi Arabia Ministry of Energy, Industry and Mineral Resources

Ministry of Energy, Industry and Mineral Resources

UAE – Federal Ministry of Energy Ministry of Energy

UAE, Abu Dhabi Supreme Petroleum Council, Executive Affairs Authority

Abu Dhabi Water and Electricity Authority (ADWEA)


UAE, Dubai Dubai Supreme Council of Energy

Dubai Electricity and Water Authority (DEWA), Dubai Supreme Council of Energy

Table 1: Key actors in the GCC power and gas sector

Source: IRENA

As the table shows that are many stakeholders and just as many perspectives on the

matter of cooperation. However, the outcome of the endeavor to put forth a road

map to a successful cooperative framework will create a higher value for all involved.


The Future Fuel Mix in Oil-Rich Nations: Economically Efficient Resource Use

A Game of Tons: the rise and fall of energy resources

After record highs of over US$ 145 USD/barrel in 2007, crude oil prices have

declined by more than 50 percent since the summer of 2014, and remain below

US$ 50/barrel well into the third quarter of 2016. These sudden jumps in prices come

as no surprise for net oil-importers as the oil market have witnessed similar high

volatility in virtually every decade since the 1970s. For importers, in addition to other

key drivers, such as sustainability, energy security, and environmental concerns,

volatility characteristics of crude oil markets have contributed to sustained efforts

seeking to develop and deploy alternative energy supply. With economic and energy

policy targets aiming to diversify energy resource use, specifically for energy-

intensive industries, all stakeholders, importers and exporters alike, must revisit the

degree of their dependence on crude oil and consider a fuel mix that is economically

optimum.

An increase in oil prices might lead to a myopic view on the dynamic between

exporters and importers, which is assumed to be zero-sum game. In other words,

higher prices yield surplus revenues for producers, and higher input costs for

importers. While this view holds true in the short-run it does not reveal outright the

full nuanced overarching relationship. Due to trade agreements, the dynamic

between different types of economies increases in complexity and would depend on

a number of factors relating to both the short and long-term impacts.

How would alternative energy demand face-off against low oil prices?

In the past, high oil prices have played a primary role in prompting the development,

deployment and adoption of alternative sources of energy. While other factors, such

as accessibility and security of supply, terms of trade, climate change concerns and

environmental friendliness in general, and efficiency of extraction and use, have

indeed played – to varying degree – an important role, determining an appropriate

energy mix is always about the bottom line. If oil prices continue to be within or near

the band of US$ 40/barrel to US$ 50/barrel, does it cool-down the motivation for and

reduce the viability of policies and plans to boost the share of various alternative

energy sources in the future fuel mix?

Although cost reduction, technological development, and other factors have driven

down the price of some renewables (e.g., wind and solar) as well as other alternative

energy sources – and could continue to do so in the future - the major sharp decline

in oil prices over the past couple of years may have outpaced the sum effect from a

steady rate of decline of these substitutes. Thus, perhaps a more intriguing question

is emerging: if alternative energy resources, including some renewables, remain or

become costlier than oil, can we expect a turnaround towards crude in future fuel

mix? A number of scenarios could play out in a such a way that the aforementioned

postulate may materialize, sooner rather than later. The reverse question is also


important, mainly: what would be the future role of crude oil – and how to safeguard

it – in the energy mix if the trend of cost reduction continues at robust rate, and

expands to other emerging alternative energy technologies under development (e.g.,

high-density, high capacity and fast-charging battery for electric vehicles)?

Ice and fire: retain or spend surplus revenues?

The energy-trade nexus might be considered by some a zero-sum game. While

higher crude prices can boost revenues and generate budget surplus for oil

exporters over the short term, it can also lead to higher input prices for

manufacturing sectors of their trading partners – thus prompting an accelerated shift

to lower cost alternatives. In the long-term, trade between the two different types of

economies will more than likely reflect higher import prices of non-oil goods for oil-

exporters, but can the surplus revenue gained by the oil producers in the short-term

offset the cumulative effect of price hike of their non-oil imports in the long-run?

Ultimately, for exporters, the answer depends on how they manage the short-term

excess revenues. Immediate spending will most likely harm oil exporters: in the

medium term, sustained higher prices prompt a decline in oil demand while

production levels are maintained. In effect, oil producers are likely to face a period

during which revenues may get squeezed and, to make matters worse, a

subsequent period of higher import prices.

For oil importers, a slowdown of economic activity is expected in short term, followed

by a boost to their economies in the medium term: as oil prices drop, due to

exporters maintaining production levels and demand declining, importers can begin

to accrue benefits. Despite an eventual decline in the average oil import prices, this

may not be passed through nor reflected correspondingly in prices of goods and

services exported to oil exporters.

Conversely, if oil exporters were to retain the additional (surplus) revenues during

the high oil price phase – call it a rainy day fund or a sovereign fund – they would be

able to smooth out and dampen the effect on the economy from the low oil price

shock that will eventually follow. Such a case is currently playing out today following

the falling oil prices since summer of 2014: only those that saved the excess

(surplus) revenues are able to withstand the shock of 50 percent decline in crude

prices.

Alternatively, some of those economies may be able to invest in assets that are able

to make use of the ‘bottom of the barrel’ oil in addressing their domestic energy

needs. The capital expenditure decision would rely on a number of factors, including

the tradeoffs between investing in the development of alternative energy sources

and investing in power generations plants that are able to burn heavy fuel oil. By no

means are these option mutually exclusive; yet, one thing is certain, without prudent

retention and investment of excess revenues, they would not be possible.

All sources must serve domestic consumption

In some oil exporting economies, additional factors may be underpinning the decline

in oil prices. At certain supply levels, for example, the excess revenue from exports,

may not be large enough to cover domestic consumption costs. In other words, it


might be more cost-effective not to export beyond a certain level; rather utilize the

supply beyond such a level for domestic consumption. In such a scenario, oil

exporters can use excess supply to generate electricity, for example, boosting oil’s

share in the domestic fuel mix.

The paradigm-shift from maximizing profit to minimizing costs may well impact crude

oil prices. Thus, maintaining production levels despite low prices does not

necessarily mean maintaining export levels as well. Exports may be reduced by way

of domestic usage. This action may allow oil producers to ride out the price slump

until a point where it is in their best interest to increase exports to original levels. In

this balancing act, it is crucial that oil-exporting economies consider all the side

effects of increasing domestic consumption of their economic livelihood (i.e., crude

oil).

The above considerations demonstrate that prices matter for the future fuel mix of

both exporting and importing economies. For exporters, higher crude prices are an

opportunity to manage the surplus revenues wisely, including to increase the

resilience of the economy allowing it to better withstand a likely low oil price period to

follow. In the same context, it is a demand-driver seeking to push up the share of

non-crude energy resources in the fuel mix. From the point of view of oil importers,

the higher the oil prices, the greater the impetus to reduce crude share in their fuel

mix.

The degree to which oil prices fall determines whether or not demand for alternative

energy is boosted. If prices of crude are low enough to extinguish incentives for

additional exports beyond what is economically feasible, then oil exporters might

hold oil at a higher share in their domestic energy fuel mix. Aside from planning for

the future and identifying trends – and apart from the monetary gain perspective –

there is no motivation to develop alternative energy in the fuel mix. Similarly, if the

price is low enough that it becomes cheaper for oil importers to use a greater

percentage of crude, there is less incentive to alter the fuel mix.

A decade ago, this dilemma may not have arisen, since renewables and other

energy sources supply had higher marginal costs. Today, with these some of these

costs falling, the balancing act of oil prices and incentives to alter the fuel mix is a

constant reality for energy markets.

Winter is coming for oil exporters

Oil exporters face the greatest risks as oil prices fall, especially economies in which

oil exports constitute a major part of national revenues. The changing climate of

energy markets has placed additional pressure on these economies to diversify both

their revenue sources and the energy sources in domestic use. The declining costs

of some renewables, coupled with the increasing availability of other alternative

energy sources, threatens to cool down economic activity for oil exporting

economies. Typically, reduced revenues result in lower government spending, which

can have the effect of reducing disposable income, in turn causing a decline in

aggregate demand and gross domestic product (GDP).


Given the current market conditions, one might make the case that winter is no

longer coming, but is already here. For oil exporters, rapid policy intervention and

fundamental changes are needed to stay warm in the cold periods ahead. The long-

term solution would be to align the interests of exporter and importers such that both

may benefit, or at least suffer the least negative impacts, associated with price

volatility. For oil-exporting economies, this will entail diversifying economic activity,

developing new strategies for the domestic fuel mix and domestic consumption, and

taking into account the future fuel mix trend of major trading partners. The winter

facing these economies requires a carefully articulated “game of tons”, in the future

fuel mix of these economies.


Reform of China’s Energy Economy: Industrial Transformation By Dongmei Chen, KAPSARC

China’s industry at a crossroads

China, since it was founded in 1949, has positioned industrial development as a core

strategy for national economic development. As the world’s largest producer of

manufactured goods, China produces about 80 percent of the world’s air-

conditioners, 70 percent of its mobile phones, 60 percent of its shoes and 50 percent

of its steel. Manufacturing has also kept the country’s annual growth of gross

domestic product (GDP) at 10 percent over the past decade. The rise of China as an

economic and trading superpower can be largely attributed to reforming the domestic

market economy to better align with globalization, but it is also strongly linked to the

strength of industrial competitiveness arising from undervalued labor, land, water,

energy and other resources.

As economic growth slows, however, China faces new challenges including falling

wages while other factor costs rise, and growing public concern for the environment

and climate change. These pressures are rising against the backdrop of a more

fundamental macroeconomic reality: the growth pattern, based on energy- and

resource-intensive investment, manufacturing and exports, has led to economic,

environmental and social imbalances over time (Bert Hofman, 2016). China’s

industry is now at the crossroads, begging the question: will a shift in the economy

from manufacturing to service – that is, a transformation away from traditional

industry – become a new success story for China in the future?

Forging a balance between energy and environment

In 2014, total energy consumption in China was 4.26 billion tons of coal equivalent

(tce). At present, 70 percent of the prime energy comes from coal, and 70 percent of

the final energy flows to the industry sector. The surge of industrial energy

consumption has become the source of new and more complex challenges for the

country’s energy policy, energy infrastructure and environment policy (Mikkal

E.Herberg, 2014).

China’s growing reliance on imported oil and gas over the past two decades has

catalyzed investment in domestic alternative energy solutions and more active

energy diplomacy in the global arena for energy security. But it is critical to recognize

that coal combustion in China accounts for 84 percent of carbon dioxide (CO2)

emissions from fuel combustion in the country (IEA, 2015), 90 percent of sulfur

dioxide (SO2) emissions, 70 percent of fine particles emissions and 67 percent of

nitrogen oxide (NOx) emissions (MIIT, 2015). The massive use of coal puts China in

the position of the world’s largest emitter of greenhouse gases (GHGs), responsible

for 27 percent of global emissions in 2014, and causes Chinese citizens to suffer the

effects of the severe air pollution. During the first three quarters of 2015, at least 80

percent of China’s 367 cities with real-time air quality monitoring failed to meet

national small-particle pollution standards (Green Peace, 2015).

http://www.globalcarbonproject.org/carbonbudget/15/hl-full.htm#FFandIndustry


Moreover, industry along China’s major water sources has polluted water supplies.

In 2014, groundwater supplies in more than 60 percent of major cities were

categorized as “bad to very bad” (Feng Hu, 2015) and more than one-quarter of

China’s key rivers are “unfit for human contact” (China Water Risk, 2015). The

Ministry of Environmental Protection (MEP) and the Ministry of Land and Resource

(MRL) released the results of a 5-year nationwide soil study, which found

that 19.4 percent of the country’s farmland is dangerously polluted (MEP and MLR,

2014). The most common problem is high soil concentrations of heavy metals (such

as cadmium, lead and zinc), which leach out from open mines and industrial sites.

China is simultaneously struggling to, on one hand, slow the pace of economic

growth to reduce the impacts of heavy industry and, on the other hand, address the

pressing challenges from energy and environmental crisis in industrialization

processes. To strike a balance, China has launched a number of major policy

initiatives. Under the central government’s Five-Year Plans (FYPs), economy-wide

targets to reduce energy intensity, CO2 emissions and environmental pollutants are a

key driving force in all industry-related energy and environment policies.

China has designed a sophisticated system to evaluate the progress towards these

targets, link the evaluation results with performance appraisals for local governors

and industrial CEOs, and enforce the implementation with variety of measures on

fiscal support, capacity building, information sharing and technology renovation. The

Top 10,000 Enterprises Program, which targets nearly 60 percent of China’s total

energy consumption and 17,000 top-emitting enterprises in 12th FYP period, is the

best case to illustrate these systematic and comprehensive actions for industrial

energy conservation. The Air Pollution Prevention and Control Action Plan (released

in September 2013), the Water Pollution Prevention and Control Action Plan (April

2015), and the Soil Pollution Prevent and Control Action Plan (May 2016), further

push forward efforts in targeted heavy industries and in high-prioritized regions/rivers

to reduce pollutant emissions. As yet, it is still unclear to what extent trading

schemes for pollutant emissions and CO2 emissions would play an effective role.

What, for example, will be the impact of environmental protection tax to heavy

industry in the near future?

Striving for structure reform on the supply side

China has had chronic excess capacity in its manufacturing industries and has

experienced three periods of severe excess capacity so far, namely from 1998 to

2001, from 2003 to 2006, and from 2009 to present (Lu Feng, 2010). In recent times,

the excess capacity has extended beyond traditional heavy industry (e.g., steel,

cement, electrolyzed aluminum and flat glass) to include emerging industries (e.g.,

solar PV, wind turbine and new materials). Over time, the aggravating trend of

excess capacity has become more severe and more extensive (Figure 1). The root

of this repeated story lies in the investment-driven growth model and distorted

market factors (e.g., financial, land, energy, resources and environment) that

governments (at both the central and local levels) usually use to stimulate

http://chinawaterrisk.org/resources/analysis-reviews/2014-state-of-environment-report-review/

http://www.zhb.gov.cn/gkml/hbb/qt/201404/t20140417_270670.htm


investment in certain priority industries (Rui Fan, 2016; Yang Zhen, 2013). The RMB

4 trillion stimulus package that China crafted to break the 2008 financial crisis has

undoubtedly exacerbated the excess capacity issues.

Figure 1: Excess capacity in China manufacturing, 2002-14

Source: National Bureau of Statistics

In 12th FYP period, China has set a national target to cut back on excess capacity

and disaggregated the target by province and by industry on yearly basis. Any new

capacity investment and approval is highly restricted for industries with excess

capacity. The targeted enterprises with excess capacity and the progress toward

targets for each province are evaluated and released publicly. To incentivize the

efforts, the central government provides financial support and fiscal subsidies for

less-developed regions, and also applies differentiated electricity prices and punitive

electricity prices for targeted industries. As for four industries with severe excess

capacity, including steel, cement, electrolyzed aluminum, and flat glass, the central

government rolled out a capacity swap program in 2014. Under this scheme, any

new project, renovation project or expansion project in these four sectors should be

swapped with existing capacity.

Since the supply-side structure reform gained attention in Chinese economic politics

in 2015 as a strategic approach to drive economic growth, eliminating excess

capacity in industry has become more of a priority. Considering the possible negative

impacts to jobs, GDP, fiscal health, and the spillover effect from one industry to

another, much debate is ongoing as to how to define targeted excess capacity and


the best approach to cut it. A more fundamental challenge is to carry out pricing and

tax reform so that the cost of energy and resources would be properly reflected in

market prices. To reduce the intervention of local government in business

investment, some argue that it is time to advance government administration

reforms, including reshaping the central-local fiscal relations and improving the

performance appraisal system for local government officials.

Striding towards a manufacturing powerhouse

China released the ‘Made in China 2025’ plan on May 19, 2015, setting the roadmap

and timelines for China’s transformation from a big manufacturing country to a strong

one (Figure 2). The plan lays out a 10-year blueprint to increase China’s

manufacturing competitiveness and drive economic growth in the context of a

slowing economy. From ‘Made in China’ to ‘Innovated in China’ reflects a shift from

focusing on Chinese products to building Chinese brands. In addition to establishing

ten priority sectors (such as next-generation information technology, aerospace and

aviation, agricultural machinery, new energy vehicles, and biomedicine and high-

performance medical devices), the Made in China 2025 plan also calls for increasing

China’s innovation capability, quality efficiency, integration of industrialization and

information technology, and green development (the State Council, 2015).

Figure 2: Roadmap for made in China 2025

Source: The State Council, 2015

The 13th FYP puts forward action that will be taken to develop a new system aimed

at streamlining the industrial- and business-management system, boosting

administrative efficiency, expediting financial system reform, promoting development

of the capital market, and enhancing the efficiency of the financial services sector in

serving the real economy and promoting industrial upgrading (Wing Chu, 2016).

While the plan presents an ambitious roadmap for upgrading China’s domestic

manufacturing, there are significant concerns over how these goals may be

achieved. Language in the plan on rigorous security reviews and shoring up

indigenous intellectual property (IP) rights, along with ambiguity about the scale and

eligibility of preferential policies, raise concerns about how the plan will impact the

competitive landscape. Although China’s technological research and development

http://www.gov.cn/zhengce/content/2015-05/19/content_9784.htm


(R&D) activities have been expanding rapidly, a recent report by UNESCO pointed

out that Chinese enterprises face problems in mismatching R&D input and actual

application output (UNESCO, 2015). Specifically, enterprises cannot effectively

commercialize their R&D achievements.

Growing leadership in the global arena

China’s growing energy diplomacy and presence in markets ranging from Central

Asia and the Middle East to Africa and even North America confirm its emergence as

an energy superpower (NBR, 2014). In the past decade, China has often been

viewed as a huge energy consumer and importer. In the coming decades, its role as

an energy investor, energy production capacity producer and exporter, must not be

neglected. The country is already moving to take advantage of its manufacturing

experience to reposition itself as a leader in the clean energy technologies of the

future: wind, solar, nuclear generation, advanced coal technologies, electric vehicles,

smart grid technology, and more energy-efficient lighting and appliances (OECD/IEA,

2016).

China is the largest trading partner to over 130 countries. It contributes over 50

percent to Asia’s economic growth, being the most important engine for the regional

economy (World Economic Forum, 2016). As the largest shareholder of the Asia

Infrastructure Investment Bank, China is also positioned to exert significant influence

on setting future priorities and strategy for the bank.

In recent years, China has significantly liberalized administrative measures on

outbound investment, encouraging enterprises to “go out” and invest overseas, so as

to enhance competitiveness and stimulate transformation and upgrading of domestic

industry. To support implementation of the ‘going out’ strategy, China has been

pushing for a new One Belt, One Road (OBOR) Initiative since 2013. The initiative

aims to promote efficient resource-sharing and regional integration of infrastructure

to benefit countries along the original Silk Road through Central Asia, West Asia, the

Middle East and Europe. It also aims to establish a maritime road that links China’s

port facilities with the African coast, pushing up through the Suez Canal into the

Mediterranean Sea (Figure 3). A US$ 40 billion Silk Road Fund has been

established, and 18 border and coastal provinces have started developing economic

projects for the initiative (Nathan Beauchamp-Mustafaga, 2015).


Figure 3: Map of One Belt, One Road

With its growing influence, China is expected to play a crucial role in global energy

governance and reshape the world’s economic politics. As China’s economy

increasingly shifts to services and domestic consumption, it remains unclear what

the cross-border economic impacts of its transformation will be. China’s energy and

infrastructure investment projects abroad also face potential political and security

challenges. Some argue that while infrastructure may bring economic benefits, it

may result in environmental damage to the project host country. Additionally, the

extent to which such projects will help to alleviate China’s phenomenal excess

industrial capacity is open to question. It may be important for China to balance its

high ambition for further engagement in global arena and the means of better

engagement in this strategic effort.

References

Bert Hofman, 2016, China’s medium-term Outlook:2016-2020,

China Water Risk, 2014 State of Environment Report Review，

http://chinawaterrisk.org/resources/analysis-reviews/2014-state-of-environment-

report-review/

Feng Hu, 2015, Groundwater under pressure,

http://chinawaterrisk.org/resources/analysis-reviews/groundwater-under-pressure/

Greenpeace, 2015, A Summary of the 2015 Annual PM2.5 City Rankings,

http://www.greenpeace.org/eastasia/Global/eastasia/publications/reports/climate-

energy/2015/GPEA%202015%20City%20Rankings_briefing_int.pdf

IEA, CO2 emissions from fuel combustion highlights 2015,

https://www.iea.org/publications/freepublications/publication/CO2EmissionsFromFuel

CombustionHighlights2015.pdf

Lu Feng, 2010, Tacking Excess Capacity, Summary of the 399th academic seminar

of the Unirule Institute of Economics.



http://chinawaterrisk.org/resources/analysis-reviews/groundwater-under-pressure/

http://www.greenpeace.org/eastasia/Global/eastasia/publications/reports/climate-energy/2015/GPEA%202015%20City%20Rankings_briefing_int.pdf

http://www.greenpeace.org/eastasia/Global/eastasia/publications/reports/climate-energy/2015/GPEA%202015%20City%20Rankings_briefing_int.pdf

https://www.iea.org/publications/freepublications/publication/CO2EmissionsFromFuelCombustionHighlights2015.pdf

https://www.iea.org/publications/freepublications/publication/CO2EmissionsFromFuelCombustionHighlights2015.pdf


MEP and MRL, National Soil Pollution Investigation Report, 2014,

http://www.mlr.gov.cn/xwdt/jrxw/201404/t20140417_1312998.htm

MIIT, March 2015, Action plan for clean and efficient use of coal in industrial sector,

http://www.miit.gov.cn/n1146295/n1652858/n1652930/n3757016/c3764068/part/376

4069.pdf

Mikkal E.Herberg, Forging a new energy and environmental balance: Conclusions

and implications for the Asia-Pacific, NBR special report, Nov 2014.

Nathan Beauchamp-Mustafaga, 2015, Chinese Provinces Aim to Find Their Place

Along New Silk Road, China Brief, Volume 15,

http://www.jamestown.org/uploads/media/China_Brief_Vol_15_Issue_10_1.pdf

NBR, 2014, China’s Energy Crossroads: Forging a New Energy and Environmental

Balance

OECD/IEA, 2016, China’s Engagement in Global Energy Governance

Rui Fan,2016, China’s Excess Capacity: Drivers and Implications,

http://www.stewartlaw.com/Content/Documents/China's%20Excess%20Capacity%2

0-%20Drivers%20and%20Implications.pdf

The State Council, 2015, Made in China Plan 2025,


UNESCO, 2015, UNESCO Science Report – Towards 2030.

Wing Chu, 2016, China’s 13th Five-Year Plan: The Challenges and Opportunities of

Made in China 2025, http://hkmb.hktdc.com/en/1X0A6918/hktdc-

research/China%E2%80%99s-13th-Five-Year-Plan-The-Challenges-and-

Opportunities-of-Made-in-China-2025

World Economic Forum, Jan 2016, Geo-economic with Chinese Characteristics:

How China’s Economic might is reshaping world politics,

http://www3.weforum.org/docs/WEF_Geoeconomics_with_Chinese_Characteristics.

pdf

Yang Zhen, 2013, Distorted Incentives for Excess Capacity: the Cause and

Countermeasures, Economist, 2013 (10).

http://www.mlr.gov.cn/xwdt/jrxw/201404/t20140417_1312998.htm

http://www.miit.gov.cn/n1146295/n1652858/n1652930/n3757016/c3764068/part/3764069.pdf

http://www.miit.gov.cn/n1146295/n1652858/n1652930/n3757016/c3764068/part/3764069.pdf

http://www.jamestown.org/uploads/media/China_Brief_Vol_15_Issue_10_1.pdf

http://www.stewartlaw.com/Content/Documents/China's%20Excess%20Capacity%20-%20Drivers%20and%20Implications.pdf

http://www.stewartlaw.com/Content/Documents/China's%20Excess%20Capacity%20-%20Drivers%20and%20Implications.pdf


http://hkmb.hktdc.com/en/1X0A6918/hktdc-research/China%E2%80%99s-13th-Five-Year-Plan-The-Challenges-and-Opportunities-of-Made-in-China-2025



http://www3.weforum.org/docs/WEF_Geoeconomics_with_Chinese_Characteristics.pdf

http://www3.weforum.org/docs/WEF_Geoeconomics_with_Chinese_Characteristics.pdf


Energy Productivity as a New Growth Paradigm By Nicholas Howarth and Kankana Dubey, KAPSARC

Managing transitions to energy productivity

Many countries are making the transition to higher energy productive growth. At the

same time countries such as USA and Australia have placed energy productivity at

the center of energy policy to encourage this transition. This session explores why

policy makers might want to encourage such a shift in the GCC and how to do so.

While most people agree that the world is in constant flux, continuing change does

not necessarily mean a transition to a new state, or more strongly, a transformation

to an evolving set of futures. Heraclitus famously said “Ta Panta Rei” that everything

flows. One cannot swim in the same river twice, but that does not mean that what is

new (the river’s water flow) is independent from what will always remain the same

(the river itself). And herein lies core of question for changing energy systems: how

does one separate out what is truly new in terms of shifts in a country’s energy and

economic system, from the evolving set of constants that make up its main features?

If making a major change to a more energy productive growth model, what key

elements should policy makers focus on?

Figure 1: Many countries have decoupled energy consumption from economic growth, but not the GCC

Source: KAPSARC Energy Productivity Kuznets Curve analysis (see readings)


Transitions require us to think not about what is in the constant flow of the news

media, or of political spin doctors disguising old wares under new labels, but of

serious changes in direction and the actions that determine new futures. While

energy productivity is a new emerging policy theme in many countries, it remains an

open question as to whether it will be used to move to something genuinely new, or

provide the cover for retreating deeper into traditional patterns of development and

thinking. In both cases there is change, but in only one a transition.

While the temptation may be to rush to focus on what is genuinely new, such as the

strategic direction outlined in the Saudi 2030 Vision, it has to be recognized that

transition can only be understood in relation to certain continuities. This means that

to effectively manage a large-scale energy and economic transition, understanding

what will stay the same is as important as grasping what will change.

Why energy productivity is important to the GCC

When speaking of countries belonging to the Gulf Cooperation Council (GCC), the

recent volatility in oil prices has intensified long-held concerns about the region’s

over-reliance on oil and gas for economic development. Economic diversification and

energy efficiency policies have assumed a new urgency, as governments carefully

evaluate the fiscal sustainability of existing growth models.

KAPSARC research puts forward that energy productivity offers policy makers a

coherent set of policies within a political narrative that might help achieve a genuine

shift to a new model of growth.

At the macroeconomic level, energy productivity describes how much value

(generally measured in GDP) can be produced using an amount of energy (generally

measured in tons of oil equivalent. It reflects both what activities are undertaken in

the economy (the degree of structural diversification) and how well energy is used in

specific activities (the level of energy efficiency). An energy productivity approach

looks to coordinate the policies required to drive the technological innovations and

investments aimed at diversification and energy efficiency with the unifying theme of

optimizing energy use in order to maximize economic value and welfare.

With energy an important part of the economy in the GCC, KAPSARC argues that

energy productivity captures a significant part of the economic reform agenda and

provides a means to organize and measure progress across several policy domains.

With its focus on maximizing economic welfare, energy productivity includes but

goes beyond the traditional areas of energy policy such as demand, supply, energy

efficiency and the fuel mix, to include economic development, urban planning,

employment and the environment.


A potentially high-risk energy paradox exists within the low energy productivity

growth paradigm. Within this paradigm, increasing living standards has been reliant

on government-led public spending and energy-intensive industrial development.

However, continued rapid expansion of such development is also cutting into the

share of domestic energy production available for exports, and therefore the original

source of government revenue used to drive growth. Moving to a higher energy

productivity growth paradigm could help navigate this paradox.

A focus on energy productivity could also strengthen GCC engagement with various

international processes. For example, a focused strategy on energy productivity

could constitute a regionally appropriate direction for ‘Green Growth’ and ‘Green

Investment’. It also aligns with goals in GCC countries’ Intended Nationally

Determined Contributions (INDCs) under the COP21 Paris Agreement on climate

change, as well as initiatives within the G-20 Energy Working Group process.

Background readings:

1. Energy productivity as a new growth model for Gulf Cooperation Council

countries, KAPSARC discussion paper*

2. Energy productivity in the GCC: Evidence from an international Kuznets curve

analysis KAPSARC discussion paper*

3. Saudi Arabia’s Intended Nationally Determined Contribution submitted to

COP 21

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Saudi%2

0Arabia/1/KSA-INDCs%20English.pdf

The macroeconomic benefits of energy productivity

KAPSARC research has investigated the specific channels by which energy

efficiency impacts the economy. These effects include: i) an efficiency effect, by

which the same output can be produced with less energy; ii) a fiscal or income effect,

in which avoided energy consumption in the domestic market increases incomes and

allows for potentially higher exports of oil; and iii) a rebound effect, where higher

incomes from i) and ii) encourage greater energy consumption.

KAPSARC has developed a general equilibrium model called MEGIR, to explore

these channels for the Kingdom of Saudi Arabia (KSA). Assuming all avoided

domestic energy consumption from energy efficiency measures is sold at

international prices and reinvested in the economy, the model suggests that

increasing energy efficiency may deliver a ‘dividend’ by boosting the anticipated rate

of economic growth by between +0.3 percent and +0.6 percent per annum by the

2040s. The difference depends on whether a pessimistic (low price and low oil

production) or an optimistic (high price and high oil production) simulation is used.

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Saudi%20Arabia/1/KSA-INDCs%20English.pdf

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Saudi%20Arabia/1/KSA-INDCs%20English.pdf


The KAPSARC model shows that if policy makers use the potential increased

income and government revenues to diversify the economy through increased

capital spending (as opposed to increased current spending such as in the form of

direct cash transfers), then the payoff is higher to society.

Background reading:

1. Potential macroeconomic and welfare effects of enhanced energy efficiency in

oil-exporting country – The case of Saudi Arabia assessed using the MEGIR

model, KAPSARC discussion paper*

Financing the energy productivity transition

Investors in the GCC face a financing challenge in relation to the transition to a

higher energy productivity paradigm. It is well recognized that low energy prices

create little incentive for households and businesses to invest in energy efficiency.

However, when system-wide benefits of avoided fuel consumption and reduced

demand for electricity are considered, energy efficiency investments can be highly

cost-effective. In this low domestic energy price environment, one key barrier to

energy productivity investment, whether it is in energy efficiency or renewable

energy, is the lack of clear mechanisms for the private sector to share in the energy

system and the anticipated national benefits.

While recent price reforms have shifted the balance of benefits more towards energy

users, it is likely that joint public-private sector actions will still be needed to catalyze

the required actions. Drawing on regional and international experience on energy

efficiency and infrastructure financing, KAPSARC research has surveyed the policy

options available to governments within a transition framework.

Figure 2: A transition framework for understanding energy productivity investment


Sources: KAPSARC analysis based on Geels and Kemp, 2006; Howarth, 2012; and

OECD, 2014

To enable such a transition, KAPSARC research suggests a range of options are

available including establishing a US$ 100 billion ‘nega-barrel’ program across the

GCC to incentivize the production of avoided energy consumption through energy

efficiency and other investments including renewable energy. This could provide a

mechanism for the private sector to share in the benefits of investments that

currently flow mainly to the state.

Other financing options to support the transition to higher energy productivity include

incorporating energy productivity criteria into existing public capital spending;

establishing a new public financing vehicle specifically for energy productivity

investment; and issuing energy productivity green bonds, including Green Sukuk

(Sharia-compliant securities backed by a specific pool of assets).


Buildings

& the built

environme

nt

Transport Industry Utilities E

ne

rgy

eff

icie

ncy

inv

es

tmen

ts

Energy

efficiency

retrofit

Buildings

structure,

systems

and

controls.

Street lights

to LED

lamps.

Vehicles

(e.g.,

aerodynami

cs, drive

train).

Processes and

equipment (e.g.,

variable speed

drives);

buildings.

Power plant,

transmission &

distribution

systems.

Ma

ins

trea

m in

ves

tmen

ts /

Mo

de

rniz

ati

on

Existing

assets

Refurbish

buildings to

make them

fit for

modern

working

and living

conditions.

Refurbish

existing

vehicles

(e.g., buses

or trains) for

non-energy

reasons.

Retrofit/ refurbish

industrial

processes for

non-energy

efficiency

reasons (e.g.,

quality,

production

output),

incorporating

some efficiency

improvement.

Retrofit/ refurbish

power plants,

transmission &

distribution systems

for non-energy

efficiency reasons

(e.g., reliability),

incorporating some

efficiency

improvement.

New

assets

within

existing

industrial

structure

New high

efficiency

buildings,

including

Near Zero

Energy

Buildings or

Net Energy

Positive

buildings.

New street

lighting

installations

.

New high

efficiency

vehicles.

New high

efficiency

production plants

using same

process.

New plants using

new processes

for existing

industries.

New high efficiency

generation plants,

and transmission &

distribution.


New

assets

driving

structural

change

Changes in

urban

planning.

Use

buildings as

part of the

power grid

(i.e., smart

buildings

and smart

cities).

New vehicle

types (e.g.,

electric

cars, buses

and trucks).

Modal shifts

(e.g., high

speed rail

links to

reduce air

transport).

New, less

energy-intensive

industries.

New technologies

(e.g., renewables,

nuclear, distributed

generation, district

heating and

cooling).

Table 1: Opportunities for energy productivity investment

Source: KAPSARC

One early option for governments to consider could be investment in retrofitting

residential buildings. With payback periods of less than one year for basic energy

efficiency programs, this is by far the most cost-effective measure. More ambitious

plans with a wider scope have longer payback periods, ranging from 13 to more than

30 years, depending on the cost of the specific action(s) and the prevailing electricity

price.

Figure 3: Estimated energy productivity investment and simulated benefits in the GCC residential buildings


Note: Analysis assumes 10-year investment implementation period and 30-year

project period and a 3 percent discount rate. Benefits to society include the full value

of avoided oil equivalent being exported at US$ 35/barrel, and avoided electrical

generation capacity of 3,787 megawatts (MW) (Level 1), 10,889 MW (Level 2),

23,673 MW (Level 3), valued using US$ 1,700 for reduced electricity CAPEX per

kilowatt (kW).

Source: KAPSARC

Background reading:

1. Investing for Energy Productivity in the GCC: Financing the Transition,

KAPSARC discussion paper*

2. Evaluating building energy efficiency investment options for Saudi Arabia,

KAPSARC discussion paper*

Energy pricing for energy productivity

The issue of energy pricing has been moving up the policy agenda of many

countries, both oil importers and exporters. The debate on pricing policies and

eliminating energy subsidies has been very active in many international forums such

as the G20, the International Energy Agency (IEA) and the World Trade Organization

(WTO). However, calls to increase energy prices raise political challenges in most

countries. Advocates of subsidies insist that energy prices must be kept low to tackle

poverty and promote economic development. In the case of oil-rich countries, the

argument is that low energy prices provide a mechanism to share national wealth

among citizens.

There is also an important question regarding the appropriate benchmark to use

when determining a ‘subsidy’. For energy importers that must pay international

prices, the answer is simple. For energy exporting countries, where the public sector

owns much of the resource and costs of energy production are far below

international benchmarks, low energy prices can be seen as a distinct competitive

advantage, rather than a subsidy

In the case in GCC countries, low fossil fuel prices have long been considered as a

measure to redistribute wealth and served as part of the social contract upon which

the region’s political model is built. Low energy pricing has indeed been an important

measure to achieve economic goals, particularly since energy-intensive industries,

such as petrochemicals, form an important part of Gulf economies.

Given this debate, several key questions arise for GCC policy makers:

To what extent should low domestic energy prices be allowed to persist as a

reasonable reflection of the extremely low cost of energy production, which

gives the region a competitive advantage in energy-intensive sectors?

In light of the need to obtain higher value of the region’s most important

natural resource, and to support energy efficiency and economic

diversification strategies, to what degree should domestic energy prices be


allowed to reflect the opportunity cost based on international benchmark

prices?

To what extent, if at all, should energy prices be allowed to move with

changes in international prices or should they continue to be set

administratively.

Figure 4: Energy prices and energy productivity

Source: KAPSARC analysis based on Enerdata, Energy Productivity uses Total

Primary Energy Supply

Shifting to a high energy productivity growth paradigm in the GCC offers a

compelling, and perhaps imperative, case for policy makers to meet domestic energy

and economic goals by generating private sector jobs, supporting the

competitiveness of existing industries, and encouraging the development of new

sectors. It will require adaptive, forward-looking policies that can capture the

synergies among the respective economic sectors, while building on – but not being

beholden to – the region’s dominant competitive advantage in low-cost energy.

Background reading:

1. Fuel, Food and Utilities Price Reforms in the GCC: A Wake-up Call for Business -

https://www.chathamhouse.org/publication/fuel-food-and-utilities-price-reforms-gcc-

business

https://www.chathamhouse.org/publication/fuel-food-and-utilities-price-reforms-gcc-business

https://www.chathamhouse.org/publication/fuel-food-and-utilities-price-reforms-gcc-business


2. Striking the Right Balance? GCC Energy Reforms in a Low Price Environment -

https://www.oxfordenergy.org/publications/striking-right-balance-gcc-energy-reforms-

low-price-environment/

3. Reforming energy subsidies: Initial lessons from the United Arab Emirates

http://www.brookings.edu/research/papers/2016/01/reforming-energy-subsidies-uae

4. Subsidy Reforms in the Persian Gulf

http://bakerinstitute.org/research/persian-gulf-energy-subsidy-

reform/#.VyJv6x4PMCA.twitter

*Note: KAPSARC discussion papers are available online, www.kapsarc.org or on

request from [email protected]

https://www.oxfordenergy.org/publications/striking-right-balance-gcc-energy-reforms-low-price-environment/

https://www.oxfordenergy.org/publications/striking-right-balance-gcc-energy-reforms-low-price-environment/

http://www.brookings.edu/research/papers/2016/01/reforming-energy-subsidies-uae

http://bakerinstitute.org/research/persian-gulf-energy-subsidy-reform/#.VyJv6x4PMCA.twitter

http://bakerinstitute.org/research/persian-gulf-energy-subsidy-reform/#.VyJv6x4PMCA.twitter

http://www.kapsarc.org/


Transitions to Decarbonized Electricity: Finding the Right Balance

The renewable energy policy paradox

Since 2010, solar installed capacity increased 4,000 percent and wind capacity 600

percent (BP, 2016). It is now clear that deployment of renewable energy sources

(RES) is driving electricity prices lower and making them more volatile. After having

captured large shares in liberalized power markets, RES could become a victim of

their own success. With low or zero marginal costs, future RES deployment could

become costlier and less scalable, while the new pricing scenario raises concerns

about system operation and future investment. Indeed, it challenges whether the

current structure of liberalized markets needs to be reformed.

Paradoxically, a successful renewable policy could, in fact, hinder the efficiency and

effectiveness of future renewable policies. Finding the right balance may mean

asking some hard questions, such as:

Are subsidies to fossil fuel generators part of decarbonization plans?

Are renewables overshadowing the potential of decarbonization alternatives –

i.e., nuclear power and carbon capture and storage (CCS)?

Are liberalized markets suitable to integrate renewable energy at a massive

scale?

Power generation around the world is shifting from fossil fuels towards

renewables

Renewable energy sources (RES) are the most popular alternative among policy

makers to transition towards a decarbonized electricity mix. Global investments in

clean technology averaged US$ 300 billion annually in the last five years. This global

shift is favored by many different elements including a decline in the cost of

renewable technologies, diversification of the generation portfolio, climate change

concerns, industrial considerations and also green energy policies.

This trend is particularly intense in Europe, where renewable energy (excluding

hydro power) generates 36 percent of the electricity in Germany, over 19 percent in

the United Kingdom, Italy and France, and 18 percent in the European Union as a

whole (Financial Times, 2016a). European countries are, in many cases, presented

as examples of a successful renewable policy, providing opportunity for others to

learn from their experiences. To date, the high penetration observed in Europe has

not been achieved in the rest of the world. In the U.S.A., renewables penetration is

around 8 percent; in China and India, it is 5 percent. Collectively, the G20 nations

now produce more than 8 percent of their electricity from green power generators.

Renewable energy is not the only option to decarbonize the electricity system.

Nuclear energy is potentially an alternative. According to the World Nuclear

Association, more than 60 reactors are under construction in 15 countries. Carbon


capture and storage (CCS) can also be used to achieve this objective. However, the

political and social problems associated with nuclear energy, and the high cost of

CCS technologies, make these alternatives less attractive for policy makers. These

challenges are why renewable energy is considered the best instrument to

decarbonize the electricity system.

Deployment of renewable technologies creates pricing challenges in

liberalized markets

Liberalized electricity markets operate under two main assumptions: that power

technologies have positive and increasing marginal costs, and that generators can

dispatch power in response to demand. Power generators make daily bids with

prices and quantities of electricity. These bids are ranked from the cheapest to the

most expensive, creating the standard supply curve with a positive slope. The

market then matches supply and demand, discarding the most expensive bids.

The very nature of RES, particularly the sharp contrasts to incumbent fossil fuel

generation, is distorting liberalized energy markets in various ways.

First, as RES technologies have low marginal costs, they tend to take first call on the

market. As the level of RES penetration increases, its deployment is having the

unexpected effect of driving down electricity prices. But RES is also intermittent, and

thus nonprogrammable: it impossible for the full spectrum of market players to plan

far ahead as incumbent generators have done in the past. The intermittency thus

has the effect of also making electricity prices more volatile (Browne et al., 2015; Clò

et al., 2015; Würzburg et al., 2013; Paraschiv et al., 2014; and Dillig et al., 2016,

among others).

In this new scenario of low and volatile prices, incumbent fossil fuel generators are

struggling to adapt. A prime example of this phenomenon was seen in Germany on

May 8th 2016, when exceptionally positive weather conditions allowed RES to supply

around 80 percent of total demand. As a result, the price of electricity was negative,

causing some generators to pay as much as € 130/MWh to generate electricity (The

Independent, 2016). An extreme scenario is conceivable in which 100 percent

renewable penetration causes the market price to collapse to zero. This is obviously

incompatible with a liberalized market.

In the short term, the low and volatile prices that come with RES deployment reduce

demand on the capacity of incumbent fossil fuel generator and, in turn, reduces their

returns. Over the longer term, it renders unfeasible the business plans on which they

were built and can eventually lead to stranded assets.

Wholesale electricity prices and costs are diverging

The emerging disconnect between electricity prices and system costs is also a

concern; here again, a price element is evident. As mentioned above, RES

technologies have very low or even zero marginal costs, a factor that drives down

electricity prices over the long term. But lower electricity prices do not imply lower

global costs for the system. In fact, very low electricity prices can have negative


effects in that they discourage investments in future generation and in energy

efficiency. In many cases, the levelized cost of electricity of RES technologies is

higher than that of fossil fuel generators.

Paradoxically (again), it is the relatively high marginal costs of incumbent fossil fuel

generators that stimulate the right incentive for investors and consumers. This is

another unexpected consequence of the massive deployment of renewables: the

price of electricity in wholesale electricity markets and the cost of the system are

diverging.

Should liberalized electricity markets be reformed?

Given these challenges, it seems clear that if governments want to accelerate a

transition towards decarbonized energy systems that maximize the share of

renewable technologies, they will also need to reform liberalized markets. In a reality,

it is quite difficult to integrate a technology that has zero marginal cost in a

marginalist market (Coase, 1946). Although some ideas have been proposed, this is

still an open debate.

In short, low and volatile electricity prices are damaging the profitability of traditional

utilities’ business models. In 2015, the 12 biggest utilities in Europe wrote off €30

billion of value from their assets. In the last six years, the total cost of impairments

amounted to more than €100 billion (Financial Times, 2016b). Additional evidence on

the difficulties the incumbent companies face in adapting to this new price scenario

is presented by Caldecott and MacDaniels (2014) and Buesser and Godrich (2015).

Ultimately, low electricity prices do not incentivize new capacity additions in

generation, raising doubts about future electricity supply.

One potential policy response to this new environment is to subsidize fossil fuel

technologies – at least to the degree that they are paid for the back-up service they

provide. While there is economic motivation for capacity payments for fossil fuel

generators, it creates another paradoxical situation: to transition towards a

decarbonized energy mix, society has to subsidize fossil fuel generators.

With these realities coming to the fore, deeper questions could emerge: if

governments have to subsidize renewable energy and fossil fuel energy, then, what

is the role of the market? Even more, are liberalized markets the best strategy to

integrate renewable energy at a massive scale?

Do policy makers need different instruments to foster a transition to

decarbonized electricity?

Many European countries that have been ‘successful’ in boosting RES technologies

are now evaluating their initial policies. There is an increasing consensus that the

policies that led to a high level penetration have become expensive. In Germany, for

example, the feed-in tariff (FIT) program supporting renewable energy has more than

doubled residential electricity prices in the last 15 years (Lang and Lang, 2015).

According to 2015 estimates, the cost of Germany’s FIT subsidy program could

exceed US$ 1.3 trillion by the time it expires. Spain virtually ceased to provide any

additional financial support for RES in 2013, due to high costs of the electricity

system.


Surely, there are important lessons to draw from the experience of these early

movers, and vital questions to ask in the evaluation process. Is the high cost of

European renewable policy the result of an ‘over incentive’ to speed the transition

process? Is it the result of a poorly designed mechanism? Or is it the unexpected

result of market behavior? The answers to these questions are currently a subject of

open debate.

What instruments have policy makers to boost the decarbonization of the

power system?

Feed-in tariffs (FITs), feed-in premiums, production tax credits and investment

credits, and direct subsidies are the standard policy tools to promote renewable

energy. Their impact on deployment of renewables, including total cost and speed of

adoption, has been studied by Bürer and Wüstenhagen (2009), Couture and Gagnon

(2010) and Menanteau et al. (2003) among others.

Carbon taxes, other taxes on fossil fuels and cap-and-trade schemes are alternative

policy tools to promote a decarbonization of an economy and its electricity mix. In

fact, many economists prefer these tools since they provide the ‘right signal’ to

investors without showing any technological bias towards a particular source of

energy. However, these policy tools are more difficult to implement from a political

perspective, and do not necessarily lead to decarbonization of the economy or the

electricity mix.

Around the world, there is an increasing interest in competitive tenders as the best

tool to promote renewable energy. Recent competitive tenders in Middle East

suggest that cost of the technology could be lower than expected. In May 2016, the

Dubai Electricity and Water Authority received bids as low as US$ 0.03/kWh for a

solar installation of 800 MW – the lowest cost ever for solar power. Some experts

argue that that competitive bidding is a better tool as FITs may not stimulate

participating parties to reduce costs or optimize their business processes in the

same way. But in some instances, bidding companies might forego part of their

profits to win a contract, viewing the up-front loss as an investment that could lead to

further opportunities. This has the effect of falsely driving down the public cost of

achieving renewable targets. Despite very promising tenders, there is not enough

evidence that these low costs will generalize in the case of massive deployment of

RES technology.

Any tool has pros and cos and, in reality, there is no ‘best’ policy option. The success

of any option depends on the objective function of the policy makers. All the

instruments mentioned here are designed for liberalized electricity markets.

Obviously, state-owned electricity systems do not have to deal with private investors

and can transit to a decarbonized economy along a less complex path. However, in

general terms, state-owned systems are less efficient than market-oriented systems,

which opens a much broader debate on the advantages and disadvantages of each

alternative.


References

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Market Uncertainty: Exploring the Impact on Renewables Adoption.” KAPSARC KS-

1639-DP033A.

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Browne, Oliver, Stephen Poletti and David Young. "How does market power affect

the impact of large scale wind investment in 'energy only' wholesale electricity

markets?" Energy Policy 87, no. C (2015): 17-27.

Buesser, Gary and Alistair Godrich. “Stranded Assets in the Utilities Secyro as

Europe Moves to a Low Carbon Society”. Investment Research, Lazard Asset

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venture capitalist's best friend? Empirical evidence from a survey of international

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for European capacity mechanisms, energy markets and climate policy." Stranded

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Clò, Stefano, Alessandra Cataldi and Pietro Zoppoli. "The merit-order effect in the

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electricity prices." Energy Policy 77 (2015): 79-88.

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169-182.

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models: Implications for renewable energy investment." Energy Policy 38, No. 2:

955-965.

Dillig, Marius, Manuel Jung and Jürgen Karl. "The impact of renewables on electricity

prices in Germany–An estimation based on historic spot prices in the years 2011–

2013." Renewable and Sustainable Energy Reviews 57 (2016): 7-15.

Financial Times. “Renewables jump 70 per cent in shift away from fossil fuels”.

August 14, 2016.

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revision–from feed-in tariffs to direct marketing to competitive bidding." Journal of

Energy & Natural Resources Law 33, No. 2 (2015): 131-146.


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quantities: choosing policies for promoting the development of renewable energy."

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Paraschiv, Florentina, David Erni and Ralf Pietsch. "The impact of renewable

energies on EEX day-ahead electricity prices." Energy Policy 73 (2014): 196-210.

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May 11, 2016

Würzburg, Klaas, Xavier Labandeira and Pedro Linares. "Renewable generation and

electricity prices: Taking stock and new evidence for Germany and Austria." Energy

Economics 40 (2013): S159-S171.


Leveraging Resources for Economic Development: Local Content

in Saudi Arabia

Changing times spur need for new approaches

A global oil price boom from 2003 to 2013 fueled rising prosperity across the

countries in the Gulf Cooperation Council (GCC). The Kingdom of Saudi Arabia

(KSA) became the world’s 19th-largest economy, as gross domestic product (GDP)

doubled, household income rose by 75 percent, and 1.7 million jobs were created for

Saudis, including for a growing number of Saudi women. The government invested

heavily in education, health, and infrastructure, and built up reserves amounting to

almost 100 percent of GDP in 2014.

The subsequent drop in oil prices in 2014-2015 dramatically changed projections for

the future. But they also provided policymakers in GCC countries with an opportunity

to finally take on economic reforms, particularly in the areas of reducing energy

subsidies and pushing economic diversification initiatives. These reforms aim to

allow resource-rich countries to capture a larger portion of the foreign direct

investment (FDI) flows for their domestic firms across the entire oil and gas value

chain. In the case of the KSA, the motivation for these reforms were spelled out

clearly in the McKinsey Global Institute’s report Saudi Arabia Beyond Oil and in the

Kingdom’s own Vision 2030 strategy, published in 2016.

Both reports placed heavy emphasis on the concept of ‘local content’ in GCC

countries and in the KSA in particular. Essentially an extension of prior labor market

reforms that date back to the 1950s, current efforts seek to increase national

participation in the workforce. With an urgent need to diversify the economy driving a

new national vision for economic transformation, there is great pressure on the

energy sector to prioritize domestics firms, retain value in-kingdom, and employ

more Saudis. This raises the question of what issues energy policymakers in KSA

need to consider as they embark on setting local content policies to meet these

goals?

Economic diversification as a political imperative in KSA

In the current and expected economic context, it is clear the Kingdom can no longer

grow based on oil revenue and public spending. In addition to the changing global

energy market, the KSA faces a demographic transition that will lead to a bulge in

the number of working-age Saudis by 2030. Current labor participation is 41 percent,

and productivity growth of 0.8 percent from 2003 to 2013 lagged behind that of many

emerging economies. Foreign workers on temporary contracts, who are paid

considerably less than Saudi nationals, constitute more than half the labor force.

A productivity-led transformation of the economy could, however, enable Saudi

Arabia to again double its GDP and create as many as six million new Saudi jobs by

2030. Eight sectors − mining and metals, petrochemicals, manufacturing, retail and

wholesale trade, tourism and hospitality, health care, finance, and construction −


have the potential to generate more than 60 percent of this growth opportunity.

KAPSARC estimates such an initiative would require about US$ 4 trillion in

investment.

The newly formed Ministry of Energy, Industry, and Minerals oversees more than 70

percent of the economy of Saudi Arabia. Ergo, it should come as no surprise that

these sectors will be a primary focus in this transformation to meet future demand for

employment.

‘Nationalization’ of industry in KSA

The KSA has grappled with the issue of how to increase national participation in the

labor market for decades. This history was summarized well by Professor Jennifer

Peck, from the Massachusetts Institute of Technology, in her comprehensive study

of labor market reforms in Saudi Arabia. Key points are as follows:

From 1995 to 2010, Saudi Arabia's nationalization (referred to as Saudization)

efforts were similar to others in the region, with extremely ambitious targets

that were not enforced on a broad scale. Under the laws of these periods,

companies in nine sectors were required to achieve 30 percent nationalization

targets, and construction companies were assigned a 10 percent target.

These laws were not enforced, however, and companies in most sectors fell

well short of these quotas. Some success was achieved in the oil and gas

industry, and in financial services.

In 2011, the Saudi Ministry of Labor began enforcing an updated version of

the old nationalization program, which had previously been on the books but

was non-binding. This new program, called Nitaqat or ‘bands’, was designed

to give firms more attainable targets and to introduce incentives to achieve

nationalization mandates. The program developed targets based on firm size

and industry, and imposed visa restrictions based on how firms performed

relative to these targets.

These incentives were strictly enforced, and non-compliers faced restrictions

on their work visas for foreign workers. By contrast, firms that performed well

were given expedited access to Ministry services such as recruiting

assistance and visa approvals. Even today, this employment quota program is

unprecedented regionally in the broadness of its scope as well as its rigorous

enforcement and close monitoring.

Peck’s research found that the Nitiqat program succeeded in increasing native

employment but had significant negative effects on firms. Program compliance rates

were high, with firms increasing their Saudization by 2.73 percent on average. Quota

compliance was primarily accomplished by hiring Saudis, and Nitaqat was

responsible for adding an estimated 96 000 Saudi workers to the private sector

workforce over a 16-month period. Significant costs, however, were encountered and

the program caused approximately 11,000 firms to shut down, raising exit rates by

nearly 50 percent. The program also decreased total employment among surviving

firms, and overall private sector employment decreased by 418,000 workers.


The pressure on Saudi Arabia’s energy sector to drive national economic

transformation and produce jobs is significant, but clearly Saudization targets such

as those used in the Nitaqat program should be considered carefully. One alternative

means to achieve these goals, which has become quite commonplace in the oil and

gas industry in other countries, are so-called ‘local content’ policies. Assessing how

they can be applied in the KSA context is a valid exercise.

Background on local content

The purpose of local content policies is to increase the value generated by exploiting

resources that remain in the domestic economy. In oil-producing countries, they also

seek to develop linkages between the oil sector and the rest of the economy. In fact,

the activity beyond the oil sector is of greater importance, as it is the ‘new’ element in

the economy (where oil and gas activity is anticipated to continue). Additionally, local

content can encompass forward, lateral and backward linkages.

Backward linkages are those created by the commercial relations among oil

operators and their supply chains, which include the transfer of technology and

know-how, employment of nationals, and sourcing local goods and services. Lateral

linkages utilize the demand of the sector to develop skills, services and infrastructure

that can positively impact on other economic sectors while allowing locals to

participate in the petroleum supply chain. Forward linkages involve the construction

of facilities that process and export these resources, such as refineries and

petrochemical facilities. These linkages are especially important to local content

policies that are a part of a country’s wider industrial policy aimed at economic

diversification and transformation.

If local content policies are implemented successfully, these economic linkages have

the potential to create significant spillovers in the economy. In Saudi Arabia, local

content objectives could contribute to the economic transformation sought by the

Vision 2030 Strategy. However, this is not guaranteed. In fact, much commentary

and analysis of local content policies in the energy sector suggest that the opposite

could be the case.

Summary of current thinking about local content

In a comprehensive World Bank study of local content in the energy sector, Silvana

Tordo succinctly summarized the arguments for and against this approach. She

concluded that governments most often pursue local content policies for three

reasons: i) to increase in-country value-added by the energy sector; ii) to correct for

a market failure; and iii) to support employment and other social objectives. Empirical

evidence supports some of these arguments.

Increasing in-country value-added occurs when domestic firms are able to produce

and export a product that was not previously produced in that setting. The challenge

for domestic energy firms in Saudi Arabia is that steep barriers to market entry for

foreign firms has led to the creation of mostly joint ventures, which minimize the role

of domestic firms. To the extent that this is a market failure, local content


requirements have the potential to develop specific skills and capacities in the

domestic workforce, thereby correcting the imbalance of knowledge between

domestic and foreign workers. Experience with local content policies in Latin

America shows that they can create productive externalities such as where local

firms begin interacting with foreign firms in technology transfer.

Such policies can, however, regularly lead to negative economic outcomes,

especially in trade as was shown by Gary Hufbauer and his colleagues at the

Peterson Institute for International Economics. In a global study, they examined 117

local content policies implemented between 2008 and 2013, across all types of

economies and industries. They estimated that these policies affected roughly

5 percent of all global trade. The net effect of these local content regulations was a

US$ 93 billion reduction in trade. Their study also points out that:

Local content policies may enable domestic producers to capture economies

of scale and enter global markets, but they insulate firms from competition

and generate lags in new technology.

The cost of implementing these policies is difficult to calculate downstream.

As local content policies seldom contain ‘sunset’ provisions, resulting market

distortions may last for a very long time.

To date, questions related to the macroeconomic impact of local content policies on

energy sector productivity remain largely unanswered. The advent of these policies

is relatively recent, and most are tied to the boom in oil and gas prices between 2003

and 2013. Thus, research on this topic is still in its infancy.

For Saudi Arabia, the question is more than academic though. The mandate for

economic transformation driven by Saudi Arabia’s energy sector makes the decision

about local content policies critically important.

Questions for consideration

Local content policies have been utilized with mixed results in several upper income

oil-producing countries. What was the overall macroeconomic impact on the

country? What was the effect on domestic firms?

In the KSA context, in light of the government’s renewed effort to diversify income

away from oil and of various new policies directed to adjust to new economic

challenges, there is some risk that GDP may be impacted negatively. How can the

government address/neutralize this negative impact? What is the capacity of

domestic firms in Saudi Arabia to meaningfully participate in the oil and gas value

chain apart from their joint venture partners?

If firm-level productivity gains depend upon an ability to produce and export new

products, how realistic is this for firms in Saudi Arabia, where the energy sector’s

innovation and technology has not traditionally been an ‘exportable’ item. Will local

content policies in Saudi Arabia be seen by foreign firms as creating an even higher

barrier to enter the market than what already exists?


ROUNDTABLE DIALOGUE BRIEFINGS – DAY TWO

Natural gas markets: the great reconfiguration? The gas industry is facing a sea of change. Declining prices and negative public

perception are adding unexpected pressures that create a degree of uncertainty not

anticipated even five years ago when gas was projected to enter its ‘golden age’.

Politically, gas is often seen as the third option, behind renewables and energy

efficiency – a reflection of the COP21 Paris Agreement commitments to reduce

energy-related emissions and the bid to achieve universal access to energy on the

global agenda. However, gas holds potential to provide cleaner energy to developing

countries at affordable costs.

It is often said that a gazelle does not have to outrun the cheetah to survive – only

the slowest gazelle. To gain market share in the future energy mix, gas does not

have to win against all competitors: rather, the industry has to be imaginative about

ways to bring gas to customers at the lowest cost so that it can outrun coal and oil,

and establish its place as a competitor for renewables and energy efficiency.

In parallel, strong policy is needed in two areas: i) to help secure future demand that

will shape pricing and stimulate necessary investment; and ii) to fully account for the

environmental and health benefits of gas, for example through carbon pricing.


The oversupplied situation will last a few years

Natural gas markets are in a state of flux. Significant supply is on its way as 150

million tons per annum (mtpa) of liquefaction capacity – a 50 percent increase

compared to 2015 levels – is coming online over the 2015-20 period. These new

liquefied natural gas (LNG) plants are arriving to the market at a time when Asian

LNG demand shows signs of weakness, having dropped by 2 percent in 2015 alone.

Globally over the past few years, natural gas demand growth has been subdued,

with rates lower (1.6 percent over 2010-15) than those experienced over the past

decade (2.8 percent).

This combination of new supply capacity and weakened demand has put downward

pressure on gas spot prices, while oil-linked gas prices have dropped in concert with

oil prices. In 2015, gas prices dropped from US$ 19/MMBtu in 2013 to levels of US$

6-7/MMBtu in Asia, and from US$ 10/MMBtu to US$ 4-5/MMBtu in Europe.

Exceptionally for a market-based commodity, this price drop – to levels unseen for a

decade – has failed to spur a demand rebound, which increased by only 1.7 percent

in 2016.

This situation confirms that a drop in prices is not sufficient in itself to boost demand;

natural gas has to be competitive against alternative fuels, notably coal and

renewables, and now even oil. Going forward, natural gas faces two issues: its price

relative to other energy alternatives and the lack of support from politicians, who tend

to prefer renewables and sometimes domestic coal. The pace at which demand will

rebound will determine when markets will rebalance and spot prices increase.

Recent demand trends

The battle takes mostly place in the power generation sector, where the switching

between coal, oil and gas is almost immediate. However, low coal prices up to mid-

2016 enabled coal-fired plants to remain competitive against gas-fired plants,

particularly in the absence of a carbon price. As the costs of renewable energies

continue a steady and significant decline, some have become more competitive

against gas-fired plants.

Despite the existence of a carbon price in Europe, gas-fired plants have had difficult

times: the region’s gas consumption has collapsed by more than one-tenth over the

2010-15 period. A slight rebound in 2015 was essentially driven by colder weather.

The situation has finally improved since summer 2016, as gas prices stayed at low

levels (around US$ 4-5/MMBtu) while coal prices rose again. In contrast, U.S.

natural gas demand has been growing because gas prices have been at record low

levels and coal-fired plants face increasing environmental pressure.

Gas demand also dropped in 2015 in some key Asian countries (e.g., Japan and

Korea) on the back of increasing competition from renewables and coal. Demand

growth stalled in China due to lower economic growth, although a drop in prices in

late 2015 seems to have boosted demand in early 2016. Overall, many developing

countries in Asia continue to favor low-cost coal for the short to medium term.


Industry, residential and transport sectors could offer long-term prospects for natural

gas, if the price is right. As oil and refined products have become more affordable,

however, they represent increased competition. In particular, the rationale of

switching from oil to gas – notably in the transport sector – is less compelling. The

case for the use of gas in transport (based on compressed natural gas [CNG] or

LNG) depends on two elements: the environmental pressure, notably the regulations

on sulfur content in the maritime sector, and the cost of CNG/LNG relative to oil

products.

An evolving and uncertain market for LNG

Not anticipating the recent demand weakness, the gas industry has continued to

invest in new gas infrastructure – notably in LNG export capacity – over the past five

years. Initial investment was driven by high oil prices as well as by a large gap

emerging between spot prices in the U.S. and oil-linked gas prices in Asia. It was

also supported by the belief that Asian natural gas (and LNG) demand would grow

substantially, with consumers ready to pay high prices for LNG for security of supply

reasons.

As a result, global LNG export capacity is on track to gain 50 percent over the 2015-

20 period. Some of this capacity has already come online, but at a much slower pace

than expected. The bulk is expected to reach global gas markets over 2017-18

(coming mostly from Australia and the U.S.), but with gas prices having crashed in

both Europe and Asia, spot prices could stay lower for much longer. Consequently,

these projects arrive in a worse environment than what investors ever anticipated:

with both oil and gas prices at record lows, projects now struggle to recover their

costs. This is likely to create the familiar boom-and-bust cycle, as only one final

investment decision (FID) on LNG export capacity has been taken in 2016 so far.

Concerns in terms of investments in both upstream and LNG export capacity are

building for the post-2020 period. Demand uncertainties and lower prices together

are likely to postpone upstream investments and the next generation of LNG projects

needed, as sponsors wait for better times and attempt to deal with high capital costs.

Should demand pick up earlier than anticipated, there is a high risk that gas prices

will skyrocket again.

Other factors also come into play, increasing the uncertainty as to where this

reconfiguration of the gas sector – and LNG in particular – is leading. The sector has

evolved from a cozy club with strong relationships among a handful of players to a

multi-business industry with new players appearing at all parts of the LNG value

chain. These new players arrive with new ideas and challenge the business model of

the 50-year old LNG industry. They also have different needs: many developing

countries are interested in electricity rather than in LNG itself, triggering more LNG-

to-power projects.

But many of the new players are relatively small – and the emergence of smaller

buyers in particular presents new risks. While they could provide much-needed

additional LNG demand, they are generally much less credit-worthy than sellers

would like.


Trading houses seem interested in this new business environment as they

increasingly participate in tenders to supply such new LNG importers. Even so,

traditional pricing mechanisms based on oil indexation are challenged. The

attractiveness of indexing U.S. LNG against Henry Hub (HH) spot prices is

challenged by low oil prices and U.S. LNG appears more expensive than oil-indexed

LNG in the current market conditions. This forces offtakers to consider the

liquefaction fee as a sunk cost, prompting two questions: to what extent will U.S.

LNG plants operate at capacity and will we see some offtakers defaulting?

Asian players are calling for the establishment of an Asian trading hub and more

flexibility on the LNG market, notably with the removal of final destination clauses in

long-term contracts. In particular, Japan is keen to play “a leading role in developing

a flexible and liquid LNG market”. Flexibility will increase as more LNG is traded on a

spot and short-term basis. But this is likely to challenge existing long-term contracts

as buyers are reluctant to extend these for another 20 years.

The overarching challenge is how new projects can move ahead in a market context

where demand uncertainties make buyers hesitant to commit for a long duration.

Many buyers come from developing countries with limited needs, and are more

interested in smaller quantities. This may call for smaller projects, possibly floating

LNG (FLNG) if the ones starting over the coming years prove an effective way to

reduce capital costs. Still, such buyers do not provide the credit-worthy counterpart

needed to convince banks to provide financial support for future projects.

All these different elements are likely to profoundly impact the way LNG is being

traded, priced and where it is consumed, which ultimately influences production.

Regional outlooks in developing countries

China plans to increase the role of natural gas as a way to tackle environmental

issues and air pollution, particularly through a significant switch away from coal in the

heating and power sectors and to meet continually increasing demand in the

transport sector. Important switching potential also exists in the industrial sector,

which consumes annually about 1 billion tons of coal. Future policy decisions that

influence Chinese prices will be key to making gas attractive in diverse sectors. At

present, the rate of economic growth is more uncertain, and gas will compete with

both renewables and nuclear.

The growth potential for gas in Africa is largely overlooked, despite much lower

energy consumption per capita and projected demand growth. With hundreds of

millions of Africans still lacking access to electricity, demand for electrification is

particularly significant. Africa has large gas reserves and the most recent discoveries

in Eastern Africa are still untapped; these resources could offer potential for both

regional use and LNG exports. The current low prices on global LNG markets are

prompting some African countries to investigate LNG imports more closely. Such

imports are largely based on floating storage and regasification units (FSRUs). In a

few cases, LNG imports are envisaged for the longer term. Obviously, the region

presents quite a high number of challenges. Significant capital investment is needed,

along with a critical mass of anchor customers. The lack of existing infrastructure

and established gas consumers, along with the low income of residential users, also


means utilities face substantial challenges in ensuring that electricity based on gas-

fired plants is affordable to customers yet sufficient to recover costs. Natural gas,

whether domestic or imported, must also be affordable in comparison with widely

promoted renewable energies. Electricity tariffs in Africa are not the lowest in the

world, but many countries face non-payment issues from poor consumers. Improving

the credit-worthiness of electricity utilities and enforcing payment discipline are

therefore crucial to attracting investment.

In India and Southeast Asia, coal seems likely to remain the fuel of choice in the

long term, as it provides a low-cost solution to the short-term aim of extending

electricity access to millions of people. At present, the environmental and health

considerations associated with coal-fired generation take a secondary seat, as does

the overarching emissions reduction target of COP21. Here again, there is high

potential for natural gas use in the power sector, but this would require strong

government policy (which is currently lacking). Governments favor coal-fired plants,

either because their costs are lower or due to the existence of large domestic coal

resources. Many of these countries also lack the pipeline and LNG import

infrastructure needed to make the switch to gas. One can wonder whether there is a

tipping point at which public opinion will reject dirtier fuels to the benefit of cleaner

alternatives, including natural gas, and where the externalities (both positive and

negative) of all fuels are fully considered.

Natural gas has a very strong role in the Middle East and is widely expected to keep

this position in the coming decades. In fact, gas demand growth in this region is

projected to be a driver for global growth of consumption. Recently, however, this

region has been experiencing a rise in regulated gas prices, albeit from a very low

level. The demand elasticity and the response to such price increases – should they

continue – is uncertain at this stage. On one side, it could prompt development of

new gas fields that currently face economic challenges caused by low domestic price

levels; but it could also stimulate greater energy efficiency and increased use of

alternatives, including renewables.

Using policy to address price and public opinion challenges

Forecasts from many institutions and companies persistently paint a bright future for

natural gas, projecting it will play a significant role in meeting growing global energy

needs. But current market conditions challenge these optimistic considerations. In

regions where natural gas consumption is expected to increase, the scale of

incremental consumption is uncertain at this stage.

In practice, unless they have the advantage of low-cost domestic gas resources,

very few countries genuinely want to significantly increase the share of natural gas in

their primary energy mix. Rather, renewable energies are attracting global support,

particularly as their deployment increases and costs continue to decline. This creates

a significant threat to the future of natural gas in the power sector


To secure its future, natural gas needs to become a fuel of choice in the minds of

politicians. It currently appears as the third preferred option, after renewables and

energy efficiency: this situation is quite unlikely to change. In some cases, natural

gas also trails behind coal, despite having lower carbon dioxide (CO2 emissions).

Almost one year after the COP21 Paris Agreement was signed, it is still difficult to

assess how it will affect future gas demand. Despite gas having lower CO2 emissions

compared with traditional fuels, its abundance and its flexibility, the fact that it is a

fossil fuel undermines its potential to fulfil an important role in energy access and

reducing emissions, at least in the short term. Also overlooked is its capacity to

address security of supply challenges, notably in Europe.

Policy can play an important role in capturing the benefits of natural gas. Pragmatic

policy would reflect the externalities related to respective fuel sources and allow the

market to decide what is most cost-effective. As domestic production is usually

insufficient to cover increasing demand, most countries are importing or will have to

import increasing quantities of natural gas. In some cases, such as India, domestic

prices have been maintained at low levels resulting in a need to import more

expensive LNG. An increase in domestic prices is very politically sensitive, but could

trigger additional exploration and production activity, and thereby reinforce the role of

natural gas in the longer term.

Finally, the natural gas industry will have to think about how to address the two

issues of costs and swaying public opinion. Both issues are very much interlinked:

an expensive and highly cyclical commodity is less appealing for consumers and for

policy makers.


Utilities of the Future: Finding a Sustainable Business Model

The changing landscape of the electricity sector

The electricity sector is undergoing major changes as technological advances are

fundamentally challenging the current role of utilities. Distributed energy resources

(DER) and digital technologies, mainly in the form of smart grids and smart meters,

threaten to disrupt the electricity market, both upstream and downstream.

In fact, the high penetration of DERs raises concerns that utilities – with finance

models primarily based on the recovery (over many years) of fixed costs through

charges based on the amount consumed – now face imminent death spirals. Thus

any reduction in sales due to distributed power could lead to remaining customers

being charged higher rates, which in turn could lead to more customers installing

DERs.

So far, no consensus has emerged on how utilities can adapt their business model to

deal with these changes, nor is there a clear regulatory framework to help utilities

navigate the complexity of the emerging market. In order to remain relevant in the

future, utilities need to evolve and adapt the way they operate and do business.

What currently exists is a multitude of views and local attempts by different countries

and companies to cope with a rapid stream of unexpected challenges.

Of the three key drivers for the new power sector paradigm – technological

advancements, business models and regulatory frameworks – finding a viable

business model is perhaps the most pressing challenge for utilities. Many key

questions need to be addressed, including:

What local solutions are emerging and is there scope for developing a ‘blue

print’ for a successful business model of the utility of the future, which can be

rolled out across regions and economies?

What lessons can be learned from other industries and particularly the shared

economy?

What is the role of digitalization, regulation (e.g., pricing regimes) and national

targets (e.g., renewables, CO2 reduction, energy efficiency) in shaping the

evolving business model?

Decentralization: a new paradigm for the electricity sector

Traditional electricity markets were designed from the top down, as large-scale

systems that run at the national, wholesale level. The new power sector paradigm is

based on higher levels of locally produced electricity from a large number of small-

scale installations, which are often customer or third-party owned.


The rapid growth of DER is challenging the status quo. By bringing electricity

generation and consumption (physically) close to each other, it has turned the

system on its head. This evolution is likely to reduce reliance on the central grid,

which may ultimately change the way electricity is purchased, transported and

consumed.

In fact, boundaries among generation, transmission-distribution and distribution-

commercialization may become blurred as any or all of these activities could occur in

the same location, e.g., in industrial settings, on buildings or even at the household

level. In the future, distribution is likely to take center stage, and to operate at local

and/or retail levels. Thus, it is likely that local considerations would override national

policies.

The system could become more complex, though, as the activity centers are

geographically dispersed. Thus, the need arises to reassess markets, remuneration,

and roles and responsibilities of the existing and new players in the power sector.

Figure 1: How the power sector could evolve from a centralized to a decentralized system


The growth of DER and its impact on utilities

As the adoption of distributed solar photovoltaics (PV) and other DERs advances, it

is becoming clear that they could jeopardize both the market architecture of the

electricity sector and the traditional utility model. Experience from countries around

the world has revealed a variety of factors – changing tariff structures, incentive

schemes, levels of competition, etc. – that presage the likelihood of a utility death

spiral.

Germany is a case in point. Its power sector transition is undergoing a bottom-up

revolution, driven by individuals who see value in being independent from suppliers

and also as an investment opportunity to take advantage of subsidized government

support. Private individuals in Germany own 35 percent of total installed renewable

energy capacity; by contrast, the combined share of the big four energy suppliers is

only 5 percent. Another key stakeholder group is German farmers, who own 11

percent of total German renewable capacity.

In the United States, third-party solar developers view themselves as competing

directly with utilities. Tariff structures and subsidized upfront investments have made

residential solar affordable for the host and contributed to a rapid adoption of rooftop

solar PV in many parts of the country.

At the sub-national level, the state of New York has taken a forward-looking

approach that can be described as evolutionary more than revolutionary. The state

sees a new role for utilities, in which they are compensated for providing a platform,

optimizing the system and promoting competitive markets for DER. Additionally, the

state sees the utilities as having new activities, such as financing DER acquisition,

billing services, and operation and maintenance of DERs. In return, they get a share

of power purchase agreement revenue.

While the threat of total collapse does not seem imminent in such countries, it is

clear that incumbent utilities are negatively affected by the growth of other segments

in the electricity business. One of the biggest challenges is future deployment of

large-scale grid projects: attracting the necessary investments would be difficult in a

context where technological trends are leaning toward greater decentralization and

digitalization at the point of consumption.

Unbundling the traditional business model: what are the options?

The evolution underway will almost certainly have an impact on the way different

products and services are designed, packaged and priced. It raises the question of

whether unbundling the traditional business models of the electricity sector would

help to address emerging challenges and create new products and services, as well

as business opportunities, driven by innovations in DER technologies in the new

electricity ecosystem.

Unbundling can take many forms. For example, the traditional value chain can be

unbundled with the creation of a platform for trading the aforementioned products

and services (energy, power, reliability, security, etc.). The new role of utilities could


be as a system integrator and platform provider. Decoupling of the electricity market

is another type of unbundling, for example, to create one market for ‘on demand’

generators (traditional producers) and one for ‘as available’ generators (DER

producers). Both markets would be managed through a system operator (a natural

role for utilities?) that coordinates and optimizes supply of electricity.

Existing players have responded in different ways to these changes. Some, for

example, have split their companies to serve specific segments of the business such

as renewables, decentralized market and digital solutions, while keeping their

traditional niche in foreign countries (Figure 2). One key example is given by E.ON,

the second largest utility in Germany. E.ON has just embarked on a major

restructuring by planning to spin off its fossil and nuclear operations, and focusing on

distribution services and investing in renewables.

Figure 2: Unbundling strategies followed by some European utilities

The role of digitalization in delivering services and shaping business models

Smart grid and smart metering technologies have the potential to make a vast

amount of data available to utilities, consumers and other market players, enabling

them to manage and optimize energy usage on an unprecedented scale. In parallel,

digitalization will make previously unfeasible market concepts, such as peer-to-peer

platforms, a real option in the new electricity market and create new business

opportunities.

These technological developments are potentially more relevant to the developing

world, where opportunity and the need exist to establish new, nimble systems (and

where legacy systems and regulatory frameworks are not deeply rooted). Will

digitalization enable a quicker and smoother transition to new business models in

regions such as the Gulf Cooperation Council (GCC), where smart technologies are

being rolled out and ambitious renewable targets are being set by governments?

Can the power sector learn from other industries and the shared economy?

Other industries, such as telecommunications, have already passed the most

challenging parts of their own journeys towards decentralization and unbundling of


the value chain. Many national telecom operators have had to reinvent themselves

as value-added service providers, while still fulfilling their original mandate of

universal service provider, which implies investing in their distribution networks.

While acknowledging the differences inherent in electricity, are there any lessons to

be drawn from their experiences to inform the debate on the future of the power

sector?

The experience of the ‘sharing economy’ can also shed light, as some of its

principles are applicable to the power sector. In the sharing economy, joint owners of

an asset can use it according to need, or rent it out when they are not using it

through a platform that brings them together with minimal transaction costs. Airbnb

and UBER are recent examples that have proven the concept can work, even

disrupting a well-established market structure.

In the electricity sector, underutilized assets are the norm rather than the exception.

For example, capacity utilization in the New York electric grid is 54 percent. This

underutilization raises questions on both payments for grid maintenance costs and

options to finance expansion. By comparison, other capital-intensive industries (such

as telecom and mobile) have seen usage rise to the mid-80 percent range. With the

growth in DER and the increasing importance of the prosumer, is there scope for

future electricity business models to borrow elements from the sharing economy

principle?

The utility of the future

Within a decentralized power system, traditional utilities have the prospect of

entering alternative businesses that may deliver attractive returns. The new

paradigm also opens up opportunities for new players in the market, from investors

to manufacturers and support services, such as energy management system

providers. While newcomers share many of the business and regulatory challenges

with incumbents, the latter have the added task of having to continue to operate,

develop and invest in distribution networks that enable the delivery of electricity and

level of service required by consumers and other players in the new market

environment.


Energy Infrastructure in India: Financing the Growth

Changing the status quo

India’s energy sector has seen several recent initiatives as it embarks on an

ambitious plan to improve the standard of living of its citizens and to provide access

to affordable, clean and sustainable energy that is supported by economically sound

development programs. Many of the initiatives, such as the 175 gigawatt (GW)

renewable energy program, target renewable solutions because of the myriad

opportunities they provide for off-grid solutions and relatively easier access to

electricity.

In parallel, fossil fuel sources have had to deal with emission regulation and global

efforts to cap carbon dioxide (CO2) emissions. Coal, India’s mainstay for several

decades, is facing serious headwinds as the world grapples with climate change.

The COP21 Paris Accord and other international fora to limit fossil fuel growth are

forcing India to review critically past assumptions about its energy security and

sustainability. As the energy status quo is changing, new challenges are emerging

including, for example:

How will India develop policy mechanisms to incorporate requirements such

as COP21 in ways that do not affect its future growth prospects at the cost of

environment and allow international funding for new cleaner fossil-based

projects to flourish along with renewable energy projects?

What policy changes does India need to undertake in order to boost

investment in energy transport infrastructure to ensure that the supply side

benefits are not frittered away?

What holistic policy mechanisms could enable integration of fossil fuel and

renewable energy infrastructure to ensure that India’s population is able to

enjoy equally the benefits of low-cost fossil fuel and environmentally

sustainable renewables?

How will these issues impact private and public financing of energy

infrastructure? What policy measures are needed to alleviate investor

concerns and also influence technology choices for a sustainable future?

The changing role of technology generates policy and financing challenges

Electricity generation

Endowed with massive coal reserves, India has for decades depended upon cheap

coal-fired generation for its electricity needs. This preference for low-cost, domestic

resources is expected to continue into the near future.

Acknowledging the environmental and health impacts of this approach, India has

been trying to increase penetration of super-critical technology for its coal-based


power plants. For the Ultra Mega Power Projects (UMPP), for example, policy

objectives mandated that only supercritical boilers be used. From 2017 onwards,

super-critical units are mandated for all new coal-fired generation. In reality, a

significant portion of India’s boiler fleet will still be based on sub-critical units, thus

hampering the policy objectives.

Additionally, while focus has been on technology choices for generation, washery

capacity – which plays a critical role in minimizing pollution at the plant level – has

not received enough attention. Existing coal-washing capacity needs to be upgraded

to meet the coal quality requirements of super-critical boilers and revised emission

norms.

Coal gasification technology, which could be the answer for effective use of Indian

high-ash coal, has received only intermittent attention. Earlier projects to develop

coal-to-liquid (CTL) and other valuable downstream products from coal have fizzled

out as policy focus has shifted.

Ultimately, India needs to take a holistic approach to clean coal development, taking

action across the entire coal chain and not only at generation. This implies

developing policy mechanisms that could help generate viable projects for

downstream coal. Additionally, as these technology solutions create a need for

substantial financial investment, India will need to find ways to encourage active

participation of private and public investors. Future expansion of the coal sector will

require new policy mechanisms that meet environmental safeguards and sustainable

development goals while also alleviating investor concerns.

Natural gas, which is often seen as a bridging fuel between coal and renewables,

has not been able to fulfill the role policy-makers anticipated in India. Because of gas

availability and infrastructure issues, existing gas power plants have operated at

either very low utilization levels or have been completely stranded. Domestic

production has not kept pace with demand because of policy issues and under-

investment. To further complicate these challenges, the domestic gas pricing

mechanism has stymied new exploration, further exacerbating the supply situation.

Greater demand for energy carriers: financing future transmission and

distribution

The electricity grid, railways and pipelines are the most widely used modes for

transporting energy commodities in India. Due to steadily growing demand, energy

transport requirements have changed significantly over the years. Physical

expansion to augment the existing energy transportation infrastructure has not kept

pace with the growing energy needs or with the energy mix composition. This has

resulted in a lack of commensurate infrastructure and/or overutilization of some

energy transportation infrastructure assets. As economic growth is inextricably linked

to energy provisioning, achieving a desired level of economic prosperity will require

significant expansion and upgrade of existing energy infrastructure – at substantial

cost.


Electricity transmission infrastructure

In India, priority has always been given to adding new generation capacities. Over

the years, this has resulted in inadequate investment in the transmission network

(both inter-state and within the state boundaries). With significant scaling up of

renewable energy targets (to 175 GW in the grid) and priority uptake, the need to

develop a stronger transmission infrastructure has become critical.

Despite significant efforts (starting in 1998) to encourage private sector participation

in the transmission business, the overall response has not been encouraging.

Project developers were put off by various challenges during execution phases, and

were also concerned about unfavorable clauses in the supporting frameworks that

aimed to encourage private investments in transmission infrastructure.

This is the context in which India has launched its renewable energy push. Yet

renewables will require transmission infrastructure that can handle the associated

volatility and is robust enough to deal with sudden spikes and surges. Existing

projects, such as the Green Corridor project and others, are not sufficient to handle

the surge in renewable generation, and the lack of transmission infrastructure

investment and development could derail any gains from the incorporation of

renewables. Development of infrastructure also has to consider the future demand

scenarios from emerging cities and the massive push towards development of ‘smart

cities’.

Railways

About 61 percent of the total installed generation capacity (as of 31 March 2016) in

India is coal-based. Although renewable energy’s contribution is increasing, coal is

expected to remain the main fuel for electricity generation in near future. With almost

two-thirds of power demand coming from the northern and western regions, while the

coal deposits are located in the eastern and central regions, India faces a massive

coal transport challenge.

Railways have traditionally relied on government budgetary support, coupled with its

own internal resources, to fund infrastructure investments. The current infrastructure

is already over-utilized and prone to under-investment. In the short term, investment

in high capacity rolling stock, as well as track and signaling infrastructure, is critical.

While some progress has been made with the Dedicated Freight Corridors in the

east and west, further development requires massive investments.

The future scenario will require support from external private investors and

multilateral funding. This means that railways will have to develop and enhance

policies, and work with investors to generate business models that will address their

concerns, which almost always coalesce around the railways’ dual role as both

regulator and operator. Policy needs to be designed to ensure sufficient space for

railways to fulfill social obligations and also provide opportunities for investors to

generate a fair return on investments.


Pipelines

Beyond providing a convenient and efficient means of transporting energy

commodities in the form of crude oil, petroleum products and natural gas, pipelines

offer economic advantage over other modes (e.g., coastal shipping of crude oil,

petroleum products by railways, road, etc.). At present, they are used to a limited

extent, with a particularly strong regional imbalance with regard to access to natural

gas. With major trunk lines located in the western-northern region, nearly 65 percent

of available gas is consumed by the states of Gujarat, Maharashtra and Uttar

Pradesh. Several other states, including West Bengal, Bihar, Jharkhand, Odisha and

Chhattisgarh, have no access to gas due to lack of pipeline infrastructure.

The existing crude oil pipeline infrastructure is also insufficient to match up demand

and supply. As demand for oil and gas is expected to increase in future (e.g.,

demand for crude oil is expected to reach 353 Mt by 2021/22), creation of supporting

pipeline infrastructure (including terminals for LNG import) becomes critical for

distribution of both domestic and imported energy resources. The Indian government

recently allowed private sector players to join the market for creating pipeline

infrastructure. However, some of the existing policy and regulatory provisions have

undermined private investor confidence in the pipeline business.

Making way for a new model for India’s energy sector

India’s energy sector has, over the past decades, very slowly moved from being

completely state-controlled and public-sector dominated to having a small presence

of private investors but still primarily state-controlled. Recent developments in

international environment management mechanisms, coupled with pressure for

economic growth to support a growing population, means that India has to address

multiple energy challenges simultaneously. The massive financing requirements to

meet growing energy demand, and the criticality of ensuring that such growth is

environmentally sustainable, create the need to radically overhaul India’s policy-

making mechanisms.


Energy Relations Between Northeast Asia and the GCC By Brian Efird, KAPSARC

The potential for alignment around energy

Countries in Northeast Asia (NEA) and those comprising the Gulf Cooperation

Council (GCC) have long been connected along the Silk Road, one of the world’s

oldest trade routes. Despite the more than 12,000 kilometers between the two

regions, they trade nearly US$ 500 billion worth of goods annually.

As the lead energy-producing region of the world, the GCC countries have a natural

affinity with countries in the biggest consuming region in the world, NEA. In 2013,

GCC countries exported US$ 367 billion worth of goods, composed almost entirely of

hydrocarbons, to NEA, accounting for a substantial proportion NEA hydrocarbon

demand (Figure 1). Thus, as a customer for hydrocarbons, NEA is critical to the

GCC and GCC is critical to helping NEA maintain high levels of energy security.

In the opposite direction, imports from NEA to GCC totaled only US$ 104 billion. As

a customer of NEA goods, the GCC countries neither heavily rely on NEA nor do

they represent a large share of NEA’s exports. To contextualize the magnitude of

these numbers, 44 percent of GCC exports flowed to NEA while only 23 percent of

GCC imports came from NEA.

Figure 1: Total trade flows from NEA to GCC, and GCC to NEA, 2013


Historically, relations between these regions have been short term and primarily focused on energy. Moreover, while both regions benefit from the relationship, the difference in level of benefit is marked, with GCC countries gaining substantially more.

As the energy sector evolves, including the current context of low oil prices and

global commitments to reduce reliance on fossil fuels, the criteria for maintaining

energy security are bound to change. This could have a negative impact on the

traditional relationship between the GCC and the NEA. But in parallel, some changes

bode well for a broader, stronger and deeper bilateral and multilateral engagement.

China’s Belt and Road Initiative (BRI), for example, sets forth an ambitious agenda

to re-establish more diverse trade along the Silk Road by extending and building

networks between these two regions (and along the route between). And while an

economic slowdown and new focus on energy efficiency and renewable energy in

NEA (particularly China) may put a dent in demand for fossils, NEA countries have

technologies and knowledge that could support GCC aims to boost energy

productivity.

The rapidly evolving context surrounding this relationship raises key questions about

its future, such as:

Can non-energy trade and relations between NEA and GCC countries

improve energy security?

How can the BRI be used as a vehicle to improve energy security for NEA

and the GCC?

What constitutes a ‘win’ with BRI for China and a ‘win’ for other countries in

NEA and the GCC?

How can the BRI be used to broaden the relationship between NEA and GCC

countries?

Energy security in NEA and the GCC

Energy security is a familiar topic for decision-makers around the world. Energy

producers worry about security of demand while energy consumers worry about

security of supply, often addressed by diversifying both types of energy and energy

suppliers. Both producers and consumers enact policies and expend resources to

protect their one-sided trade security concerns. Net exporters have diversified their

refining capability to increase market access. Net importers have developed strategic

petroleum reserves to act as a buffer against short-term supply disruptions. Both

policies are designed to reduce the cost of transaction failure when an energy shock

occurs, but both policies carry their own costs.

In the case of the relationship between the NEA and the GCC, most researchers and

policymakers view energy security as an asymmetric risk. In fact, because of the

volumes of oil and gas being imported into the NEA, the asymmetry is quite high

(Figure 2). The shortcoming of this rather unbalanced relationship is that both parties

focus on individual transactions and thus maintain a relatively short-term

perspective.


Figure 2: GCC Energy Exports to NEA / NEA Energy Imports from GCC, 2013

In fact, hydrocarbon trade between the GCC and NEA is vulnerable to three potential

shocks: price volatility, the discovery and exploitation of new or alternative fuel

sources, and even new sources of supply for conventional hydrocarbons. Any of

these shocks could reshape the energy relationship between the two regions,

suppressing economic growth and oil demand, or fundamentally altering the current

supply and demand balance and associated trade flows.

Despite this trade and the interdependence it might suggest, in other areas along the

supply and demand chain, the energy relations between the NEA and the GCC are

very limited. Restrictive upstream ownership laws in both regions have reduced joint

ventures to a handful, mostly downstream in refining or through the liquefied natural

gas (LNG) projects of Qatar.

For some years, the GCC has viewed the NEA, and especially China, as a market

without limits, able to absorb ever greater quantities of oil and gas because of its

rapid economic growth. As China’s economic expansion has slowed, and the

structure of its economy transformed, demand growth is weakening and storage

facilities are filled. The new reality is that NEA markets may no longer be able to

absorb excess cargoes. Even in China, the gas supply situation may become much

less tight by 2020, once again presenting a challenge to GCC exporters. The GCC

countries will have to decide how to respond to these changes, and also how to

address growing demand for energy within their own countries.

By contrast, the development of oil stockpiles in NEA, domestic production (in

China), and a continued search for sources of energy supply in other regions, have

lessened the NEA countries’ dependence on GCC producers. However, the GCC

countries retain a pivotal role in filling the demand for energy from the NEA

countries, if only because of the sheer volume of demand (particularly for China) and

the limited number of sources where such demand could be met with sufficient

volumes of supply.

Against this backdrop of shifting demand, energy security and the next trade need

not be the only basis for interaction. There may actually be opportunity to strengthen

and deepen the underlying relationship by broadening its scope beyond energy

trade, as both parties have other value products or services to bring to the table, and


indeed each is looking to meet other needs. Policymakers can, by adopting a

broader range of activities, extend international relations beyond energy to reinforce

mutual interdependence between economies. Building trust and relationships

between countries could adjust the focus toward the medium or long term. Perhaps

facilitating more joint ventures between countries in these regions would improve

relations by ensuring each party has “skin in the game.”

The Belt and Road Initiative and its potential impact

The BRI initiative, launched by Chinese President Xi Jinping, is intended to achieve

four main aims:

Enhance connectivity, development and trade.

Develop mutual understanding and trust.

Promote intergovernmental exchange on macroeconomic policy.

Strengthen links between China and the Arabian Gulf.

While the vision of the BRI is broad and ambitious, its shape is still developing and

implementation has been limited to date. As many details for the execution of the

BRI concept remain to be finalized, it is not clear which countries in NEA beyond

China, and indeed which in the GCC, will benefit from it. For example, the initial BRI

map did not include the GCC countries as a transit or terminal point, but subsequent

versions have been modified to include the region. As the BRI is still a work in

progress, there is opportunity to shape it with energy security in mind. Building in this

objective would require a broader assessment of the aims and preferences of

countries in the NEA and the GCC, so that concrete projects that support mutual

interests and provide a basis to expand joint trade between the regions can be

extended.

The GCC countries are a destination for traded goods. If the BRI can help expand

the flow of trade to the region, where demand for goods is increasing with growing

populations (especially in Saudi Arabia and Oman), it could be an important adjunct

to energy trade among NEA and GCC countries. But the GCC countries are more

than an end destination for trade: they also provide a critical transshipment point.

Implementing the BRI with the GCC as a clear anchor for joint development, a

waypoint, and a key destination can go a long way to building mutually

interdependent relationships.

Opportunities for a wider relationship

Historically, the relationship between the GCC and NEA has been framed in terms of

the trade of hydrocarbons flowing in one direction (GCC to NEA) and consumer

goods and technology products flowing in the other (NEA to GCC). More recently,

demand for both renewable energy and energy efficient technologies is opening up

new opportunities. The initial ‘energy’ relationship could be expanded to include

trade in renewable energy technologies and transfer of knowledge of energy efficient

processes and methods. Even better, GCC and NEA collaboration to jointly develop


such technologies and share know-how could provide a strong foundation for future

cooperation. This is not a small opportunity.

Currently, low-carbon energy provides 10.5 percent of NEA’s total energy

consumption, against a very small 0.004 percent for the GCC. Countries in both

regions are richly endowed with low-carbon energy resources, solar and wind being

the prime examples, and have targets to expand low-carbon generation.

On the GCC side, Bahrain seeks to have 5 percent renewable energy use by 2020;

Kuwait and Oman are targeting 10 percent renewable electricity generation by the

same year. Qatar has ambitious plans for 20 percent solar power by 2024, while

Saudi Arabia has called for 10 percent of electricity to come from non-hydrocarbon

sources by 2030. Dubai wants to have 5 percent of final energy consumption from

renewables by 2030.

Similar targets are found in NEA countries. China plans to increase non-fossil energy

to 15 percent of total primary energy supply by 2020; Japan is planning to more than

double its current renewable capacity by 2020 (to reach almost 86 GW), and South

Korea is targeting 11 percent by 2035.

Thus, both regions have ambitious plans to greatly expand their utilization of

renewable and low-carbon energy sources. These trends need not be seen as a

threat to the hydrocarbon trade that currently ties the countries together. Rather,

adding meaningful non-hydrocarbon sources to the energy mix ultimately frees

additional hydrocarbons for higher value uses – such as producing petrochemical

products or, in the case of Saudi Arabia, avoiding the use barrels of oil to produce

electricity. The process of freeing up hydrocarbons provides other opportunities to

forge a closer working relationship in technology development beyond the renewable

sector. For example, mechanisms to integrate non-traditional electricity production

into national electricity grids, or other challenges associated with the ambitious

targets policymakers have set for countries in these two regions.

Policymakers have thus far concentrated most on the physical links between

countries in terms of roads, railways and ports—though not concretely. A specific set

of joint and multilateral initiatives within the framework of the BRI, which recognizes

aims and preferences of countries across these two regions, could both lead to a

shared vision and stimulate joint action to accomplish the original BRI objectives.

For both NEA and GCC countries, it is important to think through the potential gains

to be achieved from the BRI. As there is a mutual interest in developing greater

energy efficiency, perhaps this could be a core link. NEA countries have great

experience in transforming their industrial sectors to become more energy efficient.

GCC countries seek to diversify their economies away from over-reliance on

hydrocarbons and to boost their energy productivity, in part by making industry more

efficient. Why not work together to achieve diversified, energy efficient industrial

sectors in the economies of both regions?


Future Path of Energy for Transport: Modes, Fuels, and

Technologies

Changes ahead in the future of transportation energy consumption

The transportation sector today accounts for about one-quarter of the world’s

delivered energy consumption and a similar share of energy-related greenhouse gas

(GHG) emissions. It is also the single largest end-use consumer of petroleum

products (IEA 2016).

Looking ahead, the transportation sector may be on the cusp of significant changes

that could dramatically impact future energy markets. Rapid developments are taking

place across areas such as new energy efficient technologies, greater use of non-

petroleum fuels for motive power, and new travel demand paradigms through

concepts such as shared mobility. Further, surging demand for transportation in

several emerging economies has reshaped the geography of energy consumption

away from industrialized economies and towards much more populous regions

where passenger and freight demand could continue to grow rapidly.

Meeting future transportation energy demand is one of the most important

challenges facing decision makers concerned about energy markets and the

environment. Interrelated questions are arising, such as:

How will new technology, fuels, and mobility conceptions impact the future of

transportation energy demand?

What is the future of transportation energy demand in emerging markets,

home to a vast majority of the world’s population?

New directions in how we move people and goods

Transportation technologies, fuel options and changing conceptions of mobility all

have the potential to significantly impact the three direct determinants of

transportation energy demand—i) demand for travel and transport, ii) energy

efficiency, and iii) fuel choice.

In the past, several factors directly affected the demand for travel, including

demographics, income, the regional economy, globalization and containerization of

freight, mode options, and land use. Undoubtedly, each will continue to play a key

role in the near- to medium-term future. However, several policy measures and

technologies are available that could reduce travel demand and improve the

efficiency of travel, such as through mode switching.

Travel demand management policies, a varied group that includes such measures

as road tolls, vehicle travel tax per kilometer, vehicle exclusion days, and increased

public transportation, could impact future demand by mode. Improved logistics could

move freight more energy efficiently while 3-D printing could localize at least some

production. What is the potential for using such policy measures and what

challenges are associated with their implementation?


The potential impact of ride-sharing is one of the most interesting questions

regarding the future of travel demand. The combination of the shared economy and

Internet connectivity could dramatically alter the relationship between personal

mobility and vehicle ownership. In much of the industrialized world, defined here as

countries belonging to the Organization for Economic Co-operation and

Development (OECD), high levels of personal travel correspond with relatively high

numbers of passenger vehicles. Could this dynamic change in the future? For

emerging economies, will shared-mobility offer personal travel, often experienced for

the first time, without high vehicle ownership rates? Could driverless vehicles reduce

energy demand by optimizing travel patterns?

Many fuel-efficient technologies available today can deliver significant reductions

in fuel consumption – and more will be widely available in the near future. Various

engine, aerodynamic, transmission, and other vehicle technologies, for example,

greatly improve the fuel efficiency of passenger cars, trucks, and large freight trucks,

which together account for about 80 percent of total transportation energy demand

(IEA, 2016). What is the role of technology in improving the energy efficiency of

various transportation modes? How quickly can these technologies be deployed and

at what cost?

Governments worldwide have implemented a wide range of policy measures to

actively promote energy efficiency in transport. Perhaps the most widely known are

fuel economy and GHG emissions standards for light-duty vehicles (LVDs – e.g.,

passenger cars and trucks), which generally cover new vehicles brought to market

over the coming decade. In recent years, the United States and China, among

others, enacted fuel efficiency measures for heavy-duty vehicles (HDVs – e.g.,

freight trucks, buses, and vocational vehicles), the fastest growing source of

transportation energy consumption. How can policy measures promote the

improvement in transportation energy efficiency?

Today, petroleum products dominate, by far, the transportation fuel market,

providing 92 percent of transportation energy needs (IEA, 2016). In the future, the

price of oil will be an important factor influencing transportation determinants. Yet,

non-petroleum energy sources for transport motive power could expand significantly,

having the side effect of reshaping global petroleum product markets. At present,

LDVs are the single largest energy-consuming transportation mode, accounting for

around half of total transport demand (EIA, 2016). As a result, much focus rests on

the possibility of bringing non-petroleum fuels in this market.

Plug-in electric vehicles (EVs) have garnered substantial attention in recent years as

a way to increase energy efficiency, reduce petroleum consumption, and, depending

on the fuel source of electricity, reduce energy-related emissions. To date, EV sales

remain small in major markets despite a plethora of policy measures to promote their

uptake. Declining battery technology costs, the potential for easier and more rapid

recharging, or even the use of driverless shared-mobility EVs all presage what may


be a much greater role in the future. What is the future market for EVs and what

challenges need to be overcome to promote expansion of EV markets?

For several of the other major transportation modes, options for alternative fuels

could be very different and perhaps more limited than for LDVs. For HDVs, maritime

vessels, and trains, which together account for around 40 percent of transportation

energy demand, natural gas is touted as an alternative to diesel and intermediate

fuel oils (EIA, 2016). Aircraft are also important consumers of transportation fuels,

around 10 percent of current total, with projections for rapid increase in aviation

demand (EIA, 2016). What is the potential for alternative fuels and related policies in

these transportation markets?

Further, the transportation sector is frequently analyzed in isolation from other

energy-consuming end-use sectors. In fact, specific transportation modes are often

investigated with little or no reference to fuel consumption trends by other

transportation modes. Do policies and technologies that impact one petroleum

product alone create challenges for refineries and, consequently, product markets?

The path ahead for transportation energy demand in emerging economies

With 4.8 percent annual growth in emerging economies against 0.4 percent in

industrialized, transport demand has made a geographical shift in the past two

decades. In 2000, around 70 percent of transportation energy demand occurred in

emerging economies, including 8 of the world’s 10 leading transportation energy

consumers (IEA, 2016). The United States, at 35 percent of world total, consumed

more transportation fuels than all non-OECD countries combined. Transportation

energy demand in these regions has since remained nearly flat. The demand

increases associated with moderate population growth and already established

transportation and urbanization patterns were almost completely offset by a shift to

more service sector-oriented economic growth and increased energy efficiency due

to policies (such as LDV fuel economy standards) (EIA, 2016).

In marked contrast, transportation energy demand in emerging economies, home to

80 percent of the world’s population, has surged in recent decades, growing at an

average annual rate 10 times that of industrialized nations. In 2014, emerging

economies accounted for 46 percent of world transportation energy demand, up from

around 30 percent in 2000 (IEA, 2016). Strong economic growth in these markets

over the last two decades has significantly increased living standards, leading to

increased demand for personal mobility but especially for freight movement, which is

tied directly to the economic production and consumption of goods (EIA, 2016).

Today, four of the world’s five largest transportation energy consumers are emerging

markets, notably China (2nd), Russia (3rd), Brazil, (4th), and India (5th) (all behind the

United States).

The rise of transport energy demand in emerging economies is, in large part, due to

the rapid economic growth of China, home to around 20 percent of the world’s

population. In 2000, China accounted for 5 percent of world transportation energy


demand; just 15 years later, its share has more than doubled to almost 12 percent.

More recently, a second wave of increased transportation energy demand started in

India, also home to around 20 percent of the world’s population (IEA, 2016).

Historically, rising incomes and economic development have been strongly linked to

increased transportation energy use. Plotting transportation energy demand per

1,000 people against real gross domestic product (GDP) per capita for the world’s 28

largest transportation energy consumers, with each dot representing a year between

1980 and 2014, reveals a trend towards greater transportation energy demand as

average incomes rise, albeit at different rates (Figure 1) (IEA, 2016; World Bank,

2016). At present, despite significant economic and transportation energy demand

growth, per-capita income and energy consumption levels in emerging economies

remain far lower than in industrialized economies. What is the future of transportation

energy demand in emerging economies, home to 80 percent of the world’s

population and what will this mean for petroleum product markets, energy

consumption, and GHG emissions?

Figure 1: Transportation energy demand per 1,000 people (y-axis) and GDP per

capita (x-axis), world’s 28 largest transportation energy consumers, 1980-2014

Sources: International Energy Agency (IEA). World Energy Statistics, 2016; World Bank, World Bank Open Data, 2016 The waves of transportation demand growth are already underway in China and

India – what can these two emerging economic and energy giants do to reduce

transportation energy demand while providing personal and freight mobility? Further,

other non-OECD countries in Asia and Africa, also representing vast populations,


could undergo rapid economic growth and urbanization in the future while also

experiencing continued population increase. New technologies, fuels, concepts of

mobility, and policies could shape a dramatically different future for their

transportation energy demand. Will these regions also experience additional waves

of transportation energy demand growth?

In industrialized economies, transportation energy demand has flattened or declined

in recent years even as average income has risen as a result of policy measures and

technology that can spread to emerging economies. Perhaps most intriguing is the

potential for current and future emerging energy giants to influence the future of

transportation energy demand in industrialized economies, as ideas, technologies,

economies of scale, and new transportation paradigms will certainly flow in both

directions.

References

Energy Information Administration (EIA). International Energy Outlook, 2016

International Energy Agency (IEA). World Energy Statistics, 2016

World Bank. World Bank Open Data, 2016


Toward More Practical Climate Change Policies By Doug Cooke, KAPSARC

The Paris Accord introduced a new ‘bottom-up’ approach in global climate

agreements, which reflects the need for context-specific policy approaches that

reflect national and regional social-economic circumstances, trade opportunities and

resource endowments. But the sum of the Intended Nationally Determined

Contributions (INDCs) proposed to date falls well short of agreed upon global

mitigation goals. Ultimately, an effective response will not be achieved unless the

sum of national policies is sufficient to reach global carbon dioxide (CO2) abatement

goals. A key collective challenge facing policy-makers is how to bridge this gap in a

timely and cost-effective manner built on a framework of differentiated national

contributions.

KAPSARC-IEEJ Practical Climate Change Policies Project

The 2015 Paris Accord represents an important step forward in global climate

change agreements. It combines national goal-setting with a global framework to

drive collective action, recognizing that each nation has unique economic, resource

and development conditions. But despite the promise of the Paris process, the

commitments made therein do not come close to meeting the world’s ambitious

decarbonization goals. This shortfall raises the question of how to ensure that

country-level emissions reductions contribute sufficiently to attaining a global goal. It

may also raise questions about an appropriate balance between mitigation and

adaptation in the longer term.

Climate change is a global challenge and all nations have a responsibility to

contribute to a global solution. However, countries’ unique starting points, socio-

economic structures, trade relations, and resource endowments make a uniform

approach across countries impractical and inequitable.

In collaboration with the Institute of Energy Economics Japan (IEEJ), KAPSARC is

developing a methodology to assess, both qualitatively and quantitatively, country-

level climate policies within a global context. We aim to calculate efficient global

pathways, establish ‘emissions envelopes’ for various countries, and explore

economically efficient and politically feasible national policies to keep emissions

within the envelopes. We illustrate the methodology by analyzing two diverse

countries: Saudi Arabia (a major energy exporter) and Japan (a major importer).

This methodology recognizes the differences among economies and that different

types and combination of policies, such as subsidy reform and utility or regulatory

restructuring, are appropriate in different contexts. The methodology focuses on

emissions reduction pathways that are economically efficient and ways to make the

bottom-up Paris strategy add up in terms of overall abatement goals. Our

methodology does not intend to assign reductions to countries or address how to pay

for these reductions. Issues such as climate finance, technology transfer, and


schemes like the Clean Development Mechanism are crucially important to achieving

global goals, but are outside the scope of this work.

Integrated modeling to establish practical emissions pathways

In the first session, we will discuss the costs and challenges of climate change

policies from a global perspective. The 2010 Copenhagen Accord codified the overall

goal of the UNFCCC process—limiting global temperature rise to less than 2°C

compared with pre-industrial levels by the end of the 21st century. The 2°C goal and

the Paris Accord focus on actions to reduce the concentration of greenhouse gases

(GHGs) in the atmosphere by reducing GHG emissions and increasing sinks for

GHGs. However, IEEJ analysis shows that the emissions reduction pledges from the

Paris Accord fall far short of actions needed to limit warming to 2°C.

We consider practical ways to minimize the impact of climate change on social

welfare by minimizing the sum of GHG emissions mitigation costs and the ‘residual’

adaptation and damage costs that result from a changing climate. From an economic

point of view, adaptation and damage are both costs that arise from not reducing

GHG emissions. Although emissions reduction is a global issue with global

implications, adaptation decisions are largely local. Determining how much to spend

on adaptation policies and projects is an important question for policy makers and an

area for future research, but this question is outside the scope of our current work.

In this work we apply an integrated assessment model that aims to represent the

economic, policy, and scientific facets of climate change. The model relates CO2

emissions to atmospheric concentration of CO2, atmospheric CO2 concentration to

ambient temperatures, and ambient temperatures to ecosystem changes that affect

economic growth. It contains simplified models of each of these impacts to relate

changes in CO2 emissions directly to economic impacts over the long term.

For our preliminary analysis of global policies, we use a modified version of the

Dynamic Integrated Climate-Economy (DICE) model developed by William Nordhaus

of Yale University. The economic portion of the DICE model considers capital

investments that reduce current consumption in order to increase future

consumption. These capital investments include the roads and factories

(infrastructure) that one generally thinks of, but also incorporate investments in GHG

emissions reduction. GHGs in the atmosphere can be seen as negative natural

capital and investments to reduce GHG emissions as increasing natural capital.

When economies devote current output to investments in emissions reduction, they

reduce current consumption to increase natural capital and prevent an economic

loss in the future (Nordhaus, 2013).

The important modification to the DICE model in this analysis is the IEEJ global

mitigation cost curve. Data making up the cost curve come from a number of

sources, including the OECD, Lawrence Berkeley National Lab, and the Japanese

Ministry of Economy, Trade and Industry (METI).


Practical emissions pathways spread costs over time

The work carried out by IEEJ and KAPSARC examined four global emissions

pathways. Two of these emissions scenarios do not consider economic efficiency.

The Reference Scenario is a business-as-usual case, without global climate policy.

The second scenario assumes a 50 percent reduction in global GHG emissions by

2050, as some experts believe is necessary to limit temperature rise to 2°C.

The other two scenarios are the result of economic modeling of practical emissions

reduction paths to minimize the economic impact of climate change. The Practical

Emissions Path uses the standard IEEJ emissions abatement cost curve. The

Practical Path with Cost Reduction after 2050 case assumes that abatement costs

decline more quickly after 2050, as new technologies are developed and become

commercial.

The modeling for each of these four cases clearly shows the reference case as

unsustainable (Figure 1). But differences among the emissions reduction cases

provide insight for policymaking. If one assumes that emissions abatement costs

decline more rapidly after 2050, emissions reach zero around 2150, just 50 years

later than if emissions decline 50 percent by 2050. The temperature differences

associated with these pathways mirror the emissions, subject to the uncertain factor

of climate sensitivity. The Intergovernmental Panel on Climate Change’s fifth

assessment report did not identify a ‘best estimate’ of the equilibrium climate

sensitivity, but instead gave a range of 1.5°C to 4.5°C. Assuming a mid-range value

of 3.0°C, the Practical Path leads to a global temperature rise of about 3°C. But if

emissions mitigation costs decline after 2050, temperature rise reaches its maximum

of about 2.5°C around 2150, then declines. By comparison, the scenario with 50

percent emissions reduction by 2050 has a maximum temperature rise of 2°C in

2100, declining thereafter.


Figure 1: Emissions pathways, in GtCO2 per year

Source: IEEJ analysis, 2016

The crucial differences among the emissions scenarios become apparent when one

examines their economic costs. A 50 percent reduction in emissions by 2050 front-

loads the cost of coping with climate change, with costs reaching nearly 4 percent of

global GDP around 2090. By comparison, the more gradual emissions reduction

paths keep costs below 3 percent of GDP at all times. The pathway corresponding to

declining emissions reduction costs after 2050 is the most desirable, with maximum

cost of about 2.5 percent of GDP in about 2140 and declining thereafter.

Figure 2: Total cost of climate change: sum of mitigation, adaptation and

damage cost (as percent of GDP)


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These emissions pathways emphasize the importance of continuing emissions

reduction after 2050. Focusing too much on early emissions reduction (before 2050)

could cause massive dislocation and economic harm. These pathways also

demonstrate the importance of continued research and development (R&D) in CO2

reduction technologies. The world can afford to delay some action on climate change

until technologies become less expensive, but the R&D to make this cost reduction

possible is crucial to minimizing the long-term impact and costs associated with

adapting to a warming world.

KAPSARC and the IEEJ plan to release a paper at the end of 2016 further explaining

this approach to formulating practical emissions pathways and building on the results

presented here. Key issues for discussion at the Dialogue include:

To what extent could the costs of climate change be spread more evenly over

time to help make the decarbonization transition more affordable?

What role could improving technology play in minimizing emissions mitigation

costs? What are the key enablers and barriers to timely, innovative and cost-

effective technological responses?

What role should adaptation play in a practical and feasible policy response?

What affordable technologies need to be developed within a global framework

of cooperation?

Using emissions envelopes to examine practical emissions mitigation

pathways

In the second session, we will explore the linkage between the global nature of

climate change and country-level policies within the KAPSARC/IEEJ methodology. A

key challenge to effectively addressing climate change is determining responsibility

for mitigation among countries. How can feasible and equitable mitigation goals be

established at a country-level that will be sufficient in aggregate to achieve a global

goal?

We propose using emissions envelopes for each country as a construct for

potentially efficient and feasible national emissions abatement goals. The emissions

envelope is a country-specific emissions pathway that is consistent with achieving a

global goal. We then explore different policies and emissions pathways that stay

within these envelopes. This approach respects the unique situation of each country

and allows a multitude of tools and approaches to be used to develop and assess a

country’s climate policy options.

We have applied this approach to examine potential carbon abatement options for

Saudi Arabia (a major energy producer and exporter) and Japan (a major energy

consumer and importer), with a view to demonstrating that an optimal mix of carbon

abatement policies can be expected to differ substantially between countries

depending on their social-economic circumstances, resource endowments and

trading opportunities. Our preliminary work uses the INDCs for each of these

countries to provide an indicative emissions envelope to facilitate the analysis.


Practical climate policies for Saudi Arabia and Japan

A key insight from our preliminary analysis of Saudi Arabia and Japan is that the

likely mix of policy responses and instruments employed in these countries are likely

to be substantially different. This reflects the unique starting points, socio-economic

structures, trade relations, and resource endowments of these countries.

For Saudi Arabia, supply-side industrial reform policies designed to increase

economic efficiency also have the potential to generate significant GHG reductions.

KAPSARC’s preliminary modeling, suggests that deregulating industrial fuel prices

may induce investments in more efficient power generation technology, resulting in a

more economically efficient allocation of resources within the Saudi energy system

and more crude oil available for export (Figure 3). By comparison, direct climate

policy instruments, such as emissions caps or carbon prices, appear to be less

economically efficient.

Figure 3: Estimated CO2 emissions from Saudi Arabia’s energy sector

Source: KAPSARC analysis, 2016

For decision-makers in Japan, the challenge is how to balance four competing

objectives: energy security, environment, economic efficiency and safety. As a major

energy importer, Japan must carefully consider its energy sources, how it transforms

energy, and how energy is consumed. Therefore, Japan’s policies and plans differ

from those of a major energy exporter like Saudi Arabia. IEEJ’s preliminary modeling

for Japan explored four potential electricity generation mixes in conjunction with

energy efficiency measures.

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Reference


Table 1: Possible scenarios for Japan

Three of the four scenarios meet the INDC target in 2030. A portfolio consisting of 50

percent thermal generation with an equal split between renewables and nuclear was

found to balance the four objectives (Scenario III in Figure 4).

Figure 4: Four possible policy options and their estimated impacts for Japan


Climate policies should be assessed not only on economics but also on political

feasibility. Policy development must also take into account the support of various

groups and interests, such as those that wish to minimize GHGs and those that wish

to maximize economic growth. Often, these interests are at odds with each other and

differ greatly by country. The proposed methodology incorporates a form of political

bargaining analysis to assess the feasibility of policies based on potential political

equilibria. The equilibrium reached among stakeholders will not necessarily be the

most economically efficient outcome.

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Our preliminary analysis raises several interrelated questions for policymakers:

How can a more practical ‘bottom-up’ approach to climate change policy

development and implementation inform the global goal-setting and

negotiation process?

What are the key challenges for developing and implementing more effective,

country-specific carbon abatement policies?

What are the most cost-effective policy instruments available to help

implement country-specific carbon abatement goals?

How could this modeling framework be applied to analyze country-specific

polices in the Gulf Cooperation Council states, China and India?