efﬁciencies and the fuel mix of generation. From an efﬁciency perspective,
thermalplants in Europe are10 to 25 percentmoreefﬁcient,onaverage,than
their U.S. counterparts (PricewaterhouseCoopers and Enerpresse 2002).
Looking at the fuel mix used in the EUand the United States, coal-based
generation exceeds 50 percent of U.S. output, whereas the EU has reduced
its use of coal to approximately 35 percent. The balance of the difference
is due to the use of nuclear (20 percent in the United States, 33 percent
in Europe). In comparing similar ﬁgures for the EU and Japan, coal and
nuclear play a greater role in the Japanese power sector, compared to the
greater use of hydro and gas in Europe (PricewaterhouseCoopers 2003).
There is a need, however, to reconcile the growing demand for afford-
able and reliable electricity supplies with the necessity to reduce greenhouse
gas (GHG) emissions. A number of options exist to address this imbalance.
In the near term, fuel switching and increased efﬁciency of production
can contribute to emission reductions. Government actions aimed at con-
trolling GHGs from large ﬁnal emitters are anticipated to accelerate the
shift in resource use from coal to gas as the primary fuel used in power
plants (Ling et al. 2004). Based on carbon prices of about ¤25 per metric
within Europe, some forecasts predict that investments in new gas
plants and writing off obsolete coal plants would be more than covered by
increased operating proﬁts arising from a predicted 40 percent rise in the
wholesale price of electricity (Leyva and Lekander 2005). Others anticipate
that a coal-to-gas transition would not take place before carbon prices
reached ¤60/metric ton CO
In the longer term, a gradual deployment of lower-carbon technolo-
gies and the expansion of renewable technologies, such as biomass, will
contribute to improved carbon proﬁles for many utilities. Demand-side
management also has a role to play in reducing the amount of electric-
ity used. Table 3.2 summarizes the different points of entry (generation,
grid, end user) and timing of where changes can be made to the energy
industry (Morgan, Apt, and Lave 2005).
Most recently, two of these technologies, integrated gasiﬁcation com-
bined cycle (IGCC) and carbon capture and storage (CCS) have gained
increased proﬁles in climate policyagendas within the European Union emis-
sions trading scheme (EU ETS) and the Kyoto Protocol’s clean development
The rapid economic growth that exists today in India and China is
closely linked to an equally increasing demand for generating capacity
and electricity. The greatest potential for large-scale cuts in CO
when coal is used is likely to come from a range of advanced technologies,
including CSS combined with IGCC. In an IGCC system, coal being used to
produce electric power is reformed, using steam, into a synthetic gas, which
can be easily separated into a concentrated stream of CO
hydrogen. The hydrogen provides a clean, carbon-free fuel for combustion,
distributed generation applications, or as a fuel for automobiles. The CO
is sequestered by pumping it underground. CSS involves the capture of ﬂue
gases exiting the combustion chamber of large point sources, the stripping
from the gases and its subsequent storage in an underground
geological reservoir. CO
can be captured from sources including power
stations, natural gas processing facilities, and steel and cement plants. This
combination of IGCC and CCS can deliver power plant efﬁciencies in the
region of 50 percent, with only 3 to 4 percent energy penalty for CO
capture and handling.
In the CCS process, CO
can be stored in geological reservoirs that are
more than 800 meters below ground level,in depleted oiland gas reservoirs,
deep saline formations both on and offshore, and can be used in enhanced
oil recovery (EOR) and coal-bed methane retrieval processes. The oil and
gas industry can offer a wealth of knowledge and experience both in storage
in depleted oil and gas ﬁelds and in the well-established use of CO
for EOR. The capture and transport of carbon, in itself, requires energy and
creates emissions, but net CO
emissions are estimated to be cut to just 10
to 20 percent of a plant that does not use CCS. The electricity industry is
anticipated to be one of the greater users of carbon capture and storage.
(See Box 3.1.)
BOX 3.1 CARBON CAPTURE AND STORAGE
(CSS) PILOT PROJECT BY VATTENFALL
The Swedish power company, Vattenfall, has taken the ﬁrst step
toward developing a commercial CCS system for carbon-free power
generation based on coal. The institution is building the world’s ﬁrst
30MW thermal pilot plant for CO
capture near its lignite-ﬁred power
plant in Swartze Pumpe in Germany. It is scheduled for completion
Among the different technologies that exist for CO
tenfall has chosen an ‘‘oxyfuel’’ combustion system,wherein oxygen is
mixed with recycled ﬂue gas containing CO
,and then used for com-
bustion,resulting in aﬂue gas that contains onlywater and CO
will be stored in subsurface geological sites, such as depleted oil
and gas ﬁelds.
Source: Str¨omberg, von Gyllenpalm, and G¨ortz 2005.
Summary of Availability of New Technologies Affecting the Electricity Industry
Integratedgas combined cycle
conversion efﬁciency; well
suited to meet intermediate
and peak demands
Gas price and supply
uncertainty; still emits some
No direct CO
High cost, public perception,
spent fuel, security
Cost of collection; aesthetics;
technical limits to % that can
be co-ﬁred with coal
Most competitive renewable
energy option; recent
growth driven by incentives
(taxes, credits) and
Land availability; aesthetics;
high cost of storage
Solar Photovoltaic (PV) power
High % of CO
Intermittent; conversion is both
expensive and inefﬁcient
Hydrogen (used in fuel cells)
Potentially large CO
reduction from electric
Hydrolysisof water is costly;
natural gas (HC
gasiﬁcation the most likely
Internal combustion engines
Use of natural gas reduces
emissions; use of
CHP3; increases end-use
Many current regulations limit
distributed generation and
Use of natural gas reduces
emissions; use of CHP
increases end-use efﬁciency
Many current regulations limit
distributed generation and
Advanced ﬂow control systems
Improved system efﬁciency
Market learning needed tobring
Reduced line losses
Greater control over power
Energy Efﬁcient End-Use Devices and Advanced Load Control
devices and advanced load
Reduce energy consumption
Mainly behavioral and
More efﬁcient end-use
Source: Adapted from Morgan, G., J. Apt, and L. Lave. 2005. The U.S. Electric Power Sector and Climate Change Mitigation.
Pew Center on Global Climate Change, Arlington, VA.
Current Large-scale Carbon Dioxide Capture and Storage Projects
Norway (offshore) Sleipner
Saline Formation Gas processing
Source: Kessels, J., and H. de Coninck. 2006. Going underground. Environmental
Reﬂecting the growing importance of CCS technology, a U.K.-based
Carbon Capture and Storage Association (CCSA) was ofﬁcially launched in
March 2006, with most of its members being in the energy sector. Its goal
is to promote technology that can store CO
permanently underground and
to investigate incentives that would encourage such development. CCSA
envisages working with the U.K. government to resolve any regulatory
issues that may cause delays in the deployment of such new technology
Three major geological CO
storage projects are already in operation
(Table 3.3). Each has the annual capacity to store approximately 1 million
tons of CO
Other companies, such as Shell and Statoil, have plans to
in a new power plant in Norway and use up to 2.5 million
metric tons per year of the CO
for EOR in offshore ﬁelds near Norway.
Two similar projects are proposed byBP in Scotland and California (Kessels
and de Coninck 2006).
CCShas gained recent prominence, with the EUETSand CDMsoffering
potential ﬁnancial incentives for companies to implement more CCS power
stations. Within the Kyoto Protocol framework, the application of CCS
offers a great potential for carbon credit projects in China and India,
as well as the possibility of developing markets for the export of clean
coal technologies (Cook and Zakkour 2005). However, the two projects
that have been submitted to be eligible under the CDM have provoked
At present, CCS technology is expensive, but further research and
development could bring the costs down considerably. The EU ETS has set
an incentive for the introduction of CCS on a large, commercial scale, but
the economic viability of CCS will depend to a great extent on the price at
allowances are traded. A recent report by the Intergovernmental
Panel on Climate Change (IPCC) (2005a) suggests that the use of such
technology would only be economic when CO
prices rise above $25 to $30
per metric ton. If technological costs remain high, new CCS technologies
are not likely to be introduced commercially.
Afurther major challenge of making CCS commercially viable is the
development of a legal framework for CO
storage. At present, there are
no regulations relating speciﬁcally to long-term responsibility for storage,
although someglobal and regional environmentaltreaties on climate change
and the marine environment may be relevant to the permissibility of CO
storage (IPCC 2005a).
INTEGRATED OIL AND GAS INDUSTRY
At present, the oil and gas sector is undergoingprofound structural changes.
The globalization of the gas industry, the rise of new emerging market play-
ers, and the worldwide reach of investors’ involvement have all contributed
to the creation of a more competitive and complicated industry. At the
same time, companies within this sector are major emitters of GHGs, and
as such are facing a number of challenges related to climate change risks.
The industry is vulnerable to:
Government mandates in areas such as gas ﬂaring and facility abandon-
The direct impacts of adverse weather brought on by climate change
(see Chapter 4).
The shift away from oil toward natural gas in recent years, as natural
gas is viewed as a cleaner fuel from a climate change perspective.
The political and legal risks that confront companies within the sector
as they seek new sources of reserves.
The major challenges in these areas are outlined below.
Gas ﬂaring: Gas ﬂaringis known to have a negative impact with respect
to global warming and climate change. Nigeria and Angola, alone,
account for approximately 15 percent of global gas ﬂaring activity.
To address this worldwide concern, West African governments have
agreed to cease ﬂaring activities in 2008. The rise in the global liqueﬁed
natural gas (LNG) industry has, however, allowed for an economically
beneﬁcial transition from ﬂaring to exportation of LNG.
Facility abandonment: The looming liability of decommissioning
mature sites is expected to be signiﬁcant as regulations governing the
abandonment of facilities such as drilling platforms in the North Sea
come into effect. However, such concerns have stimulated the industry
to look at alternative uses for the platforms, such as offshore wind and
wave power generation facilities (Ling et al. 2004).
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Volatile global weather conditions that are often associated with climate
change have increasingly been found to interrupt activities in major oil and
gas production in such areas as the Gulf of Mexico. The 2002 and 2004
hurricane seasons resulted in substantial losses of oil and gas production
in this region. Then in 2005, Hurricanes Katrina and Rita wrought both
physical loss and economic damage to the oil industry in theGulf of Mexico,
damaging oil rigs, temporarily knocking out 95 percent of its oil reﬁning
capacity and 88 percent of its natural gas production, and causingsomepro-
duction and reﬁning capacity to be completely shut down (Laidlaw 2005).
Indeed, the devastation is considered to be the world’s ﬁrst ‘‘integrated
energy shock,’’ which disrupted the ﬂows of oil, natural gas, and electric
power simultaneously (Yergin 2006).
Restricted Access to Oil and Gas Reserves
The oil and gas industry is also facing growing challenges in its attempts to
gain access to new reserves. Politicaland legalrisks have created uncertainty
in the Middle East and in many potential new sources, such as Russia and
Nigeria. In addition, increased energy prices have produced a resurgence of
nationalist policies in oil-producing countries, with a return to a 1970s style
of ‘‘resource nationalism.’’ Writing in the journal Foreign Policy, Thomas
Friedman (2006) describes this inverse relationship between the price of oil
and the pace of freedom as ‘‘the First Law of Petropolitics,’’ wherein the
price of oil and the tempo of democratic reform always move in opposite
directions in oil-rich states. This power shift has been observed recently in
The Bolivian and Russian governments have taken outright control of
oil and gas ﬁelds.
Nigeria and Kazakhstan give highly preferential treatment to state
companies over foreign installations.
Ecuador seized the assets of Occidental Petroleum Corporation in May
2006 and raised taxes on oil companies to 50 percent when prices go
above the levels stipulated in contracts.
The Venezuelan government asserted its hold on 32 small oil ﬁelds
developed by foreign companies and increased taxes from 56.6 percent
to 83 percent.
There is concern that states, intent on taking over their oil industries,
often cut back on exploration and production by diverting their newfound
oil revenues to costly social, health, and education programs, as well as
other necessary reforms. Lack of reinvestment in the industry erodes both
exploration and production levels of the very resources that they are so
eager to exploit. This effect has already been seen in Venezuela, where the
government cut its oil export target for 2006 by 100,000 barrels a day.
In addition, these actions threaten to drive away foreign capital and
future private investments in the oil industry, precisely when they need
it most. Friedman (2006) expresses a further concern that such a swing
in Petropolitics could have far reaching implications for global stability.
Japan, for example, being the world’s third largest consumer of oil (after
China and the United States) is heavily reliant on oil imports. With nearly
90 percent of its imports coming from the Middle East, Japan’s sources
of supply becomes susceptible to Petropolitics, and may oblige Japan to
overlook the actions of petro-authoritarians, such as Iran and the latter’s
dedication to nuclear technology (Barta 2006).
Further constraints to development and production of oil and gas
reserves are found in the difﬁculty of reaching their sources in technically
remote regions such as the Arctic and Asia-Paciﬁc.Goldman Sachs estimates
that over 70 percent of future energy assets will come from non-OECD
countries by2012,up from 21 percent in 1970 and 42 percent in 2002 (Ling
et al. 2004). Such projects will require not only traditional geological and
technical skills, but also the ability to work with diverse partners, national
oil companies, host governments, and nongovernmental organizations. This
has certainly been the experience of Niko Resources Ltd., a Canadian
company from Calgary, in its pursuit of gas reserves in Bangladesh. Niko
has been involved in price disputes with thehost government, and has had to
meet angry villagers’ demands for compensation for gases that were leaking
out in the marketplace. In the aftermath of a blowout, it suffered lawsuits, a
frozen bank account, verbal attacks by citizens, and daily denunciations by
the local media. Top executives at the company are quoted as saying that
it is of crucial importance to understand the political landscape
when investing in a foreign country—and never to assume it is
similar to Canada. (York 2006)
The oiland gas sector has encountered other challenges in gaining access
to resources as communities in remote regions oppose increased production
in their effort to protect pristine areas and fragile ecosystems. Past troubles
encountered by Texaco in Ecuador, and Shell in Nigeria, herald future
difﬁculties within the sector. Present-day constraints in this respect are seen
in the Arctic National Wildlife debate within the United States and the
Mackenzie River natural gas pipeline in Canada (Austin and Sauer 2002).
The transportation of oil and naturalgas by tankers is also experiencing
its own form of opposition. In Canada, Enbridge Inc.’s gateway pipeline
project is encountering resistance to the prospect of its ships (bulk-liquid car-
riers) traveling through narrow channels off the coast of British Columbia,in
order to export its oil sands crude to China (Ebner 2006). On the Canadian
east coast, there is concern about the planned siting of an LNG terminal on
the U.S. Passamquoddy tribal lands adjacent to Eastport, Maine. Proposals
for LNG plants have been considered and rejected in other locations on
the U.S. eastern seaboard because of their potential negative impacts on
tourism. Now, the citizens of New Brunswick, Canada, are distressed about
the choice of the St. Croix River as an LNG facility location, because of the
effects of enormous tankers navigating through narrow Canadian territorial
waters. Head Harbor and the Canadian side of Passamaquoddy Bay hold
great importance for the region, with its aquaculture, lobster and ﬁshing
industries, and seasonal tourism (Norris 2005).
The Coming Age of Gas, and Beyond
Concerns over climate change and political instability in the Middle East,
as well as advances in gas-to-liquid technologies, are seen to be driving
the intensity of research and development in the gas sector. As previously
discussed, about three-quarters of global proven gas reserves are in the
former Soviet Union and the Middle East. Due to the political uncertainty
in these regions, it is felt that potential political risk in these areas may not
attract the massive investment needed to develop these industries. This may
provide one explanation for the emergence of Qatar as the Middle Eastern
kingpin of gas, while other areas such as Iran and Saudi Arabia remain
largely untapped (Economist 2004b; Saunders 2006).
In the United States, demand for gas is growing at just below gross
domestic product (GDP) levels, while oil demand growth is less than half
of that. Consumption of gas in that country is predicted to overtake oil as
early as 2015 as Americans seek a ﬂexibility within their energy strategies
to alleviate energy sourcing concerns. In addition, an increasing focus on
climate change will accelerate this move to gas, since emissions from gas
are 25 percent less than from oil, and 50 percent less than from coal (Ling
et al. 2004).
To date, LNG has been the focus of the gas industry in the United
States, with LNG imports projected to increase every year at an average
rate of 8.6 percent. More recently, however, attention has been turning
to gas-to-liquid (GTL) capacity (Box 3.2), notably in the Arabian emirate
of Qatar, which has little oil but an abundance of natural gas. In 2006,
Qatar Petroleum and South Africa’s Sasol opened a GTL facility that
has the capacity to transform Qatar’s abundance of natural gas into a
BOX 3.2 GAS-TO-LIQUID TECHNOLOGIES
AND STRATEGIC DIESEL FUEL
Gas-to-liquid (GTL) is a reﬁnery process designed to convert natural
gas or other gaseous hydrocarbons into longer-chain hydrocarbons.
The GTL Fischer Tropsch process can produce a high-quality diesel
fuel from natural gases, coal, and biomass. Using such processes,
reﬁneries can convert some of their waste products into valuable fuel
oils, which can be sold as, or blended with, diesel fuel. This process is
becoming increasingly signiﬁcant as crude oil resources are depleted,
while natural gas supplies are projected to last another 60 years. In
addition, GTL fuel can be blended with noncompliant California Air
Resources Board (CARB) diesel fuels to comply with more stringent
diesel standards in regions such as California.
Source: Economist 2006d.
synthetic fuel similar to diesel. GTL diesel has a number of advantages
over LNG: Vehicles can run on it, it does not require as much dedicated
infrastructure as LNG, it is cheaper to ship than natural gas, and it can
be shipped in normal tankers and unloaded at ordinary ports (Economist
2006d). Although the GTL industry is in its infancy, recent data regarding
this middle-distillate process suggests that GTL could challenge traditional
oil reﬁnery production. In addition, GTL’s capability of producing nearly
zero sulfur transportation diesel could accelerate the oil-to-gas transition.
Thus, companies that dominate the global gas industry will have a distinct
advantage in the markets in the near future (Ling et al. 2004).
In the longer term, the focus of development in energy sources will
be in the area of renewables from wind, solar power, wave, and biomass,
as outlined in Chapter 2. At present, wind is the renewable source that is
most economically viable. However, many energy companies have already
made substantial investments in a variety of renewable energy projects, in
response to both national and regional policy initiatives.
In the EU, the United Kingdom requires 10 percent of U.K. electricity
to be supplied by renewable sources by 2010.
The sustainable energy industry in Australia is growing at about 25
percent per year (Innovest Strategic Value Advisors 2004).
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