Overall, the energy year of 2013 was marked by changes to the global energy
map. Intensification of production of non-conventional oil and gas, the
progressive abandonment of nuclear energy and the increased adoption of
renewable energies have come to change our view on the distribution of the
world’s energy resources. The major importing nations are now becoming
exporters, whilst nations that for many years have been seen as exporters are
now taking on an important role in the demand for energy.

The International Energy Agency (IEA) in its New Policies Scenario states that
despite recent developments and new policies, this will only have a marginal
impact on long-term trends for energy and climate.

According to IEA forecasts – New Policies Scenario – world energy demand is
expected to grow by more than 30% up to 2035.

In the long-term, the evolution in energy related CO2 emissions points to an
increase of 3.6°C in the average temperature

(above the target limit of 2°C for average global temperature increase).

The IEA estimates that emerging economies will account for 90% of the increase
in the demand for energy by 2035. China will lead the way in the demand for
energy during the current decade, until India assumes the mantle from around
2020. In short, China will be the main oil importer and, in 2020, India will be
the main coal importer. The Middle East will emerge as an area of increased
consumption. In 2020, it will be the second biggest consumer of gas and, in
2030, the third biggest consumer of oil. In OECD countries, the increase in the
demand for energy will be largely insignificant.

Over the next ten years the role of the OPEC countries as the major source of
oil will be temporarily reduced due to increased production in the United States,
Canada and Brazil. However, around the middle of the 2020s, oil production
in non OPEC nations will begin to decrease and the Middle East nations will
reassume the predominant role on a global scale.

As far as the energy sources in use, and despite the rapid growth in renewables,
the dominance of fossil fuels will continue, tending towards a reduction in
weighting in the global mix from the current 82% to 76% by 2035.

The flexibility and environmental advantages of natural gas, compared to other
fossil fuels, will be seen as the main reasons behind its increased long term use.
The demand for natural gas will increase by almost 50% by 2035, as a result
of the increased growth of emerging economies. New sources of gas, both
conventional and non-conventional, will contribute to a greater diversification in
the global supply of gas.

World demand for electricity will continue to grow, with an increase of two
thirds expected by 2035. World demand for electricity will continue to grow,
and an increase of over two-thirds is expected by 2035. The IEA expects that
renewable energies will supply almost half the expected increase by 2035, with
variable energy sources – wind, solar and photovoltaic – accounting for 45% of
this increase. Coal will be the major fossil fuel, with a significant increase in OECD
nations. Natural gas will represent the greatest increase in absolute terms, seeing
an increase in all regions. Overall, the percentage of renewable energy sources
in the production of electricity is expected to exceed 30% in 2035, ahead of
the share of natural gas but still below that of coal Nuclear energy, in spite of a
reduction in the construction of new plants due to regulatory restrictions, will still
account for 12% of overall global production (due to expansion in countries such
as China, Korea, India and Russia).

In this period, the IEA estimates that the electricity sector will require global
investment of approximately 17 billion dollars, with more than 40% of this
investment dedicated to transmission and distribution networks.

In spite of the introduction of new policies in the field of energy efficiency in
various regions, we are still a long way from achieving our goal. In the IEA’s
New Policies Scenario, two thirds of the economic potential to improve energy
efficiency remains untapped, pointing to a need for measures to eliminate the
barriers to investment in this field.

Demand and production of electricity

Demand and production of electricity

In 2013, electricity consumption supplied by the public network totalled
49.2 TWh, an increase of 0.2% on the previous year. This change is null taking
into consideration the effects of the temperature and number of business days
However, a recovery was seen in consumption taking place in the second half
of the year, given that at the end of the first semester there was a drop of 1.7%.
Following two years of contraction, the consumption levels seen in 2013 were
only 5.8% below the historical maximum of 2010.


2009 49.9 -1.4% -1.8%
2010 52.2 4.6% 3.3%
2011 50.5 -3.3% -2.3%
2012 49.1 -2.9% -3.6%
2013 49.2 0.2% 0.0%

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The maximum power output on the national system occurred on 9th December,
with 8 317 MW, almost 1 000MW below the historical maximum registered
in 2010. The installed capacity also suffered a reduction in 2013 with the
declassification of the Setubal fuel oil plant which had been in operation since
1979. With the declassification of this plant, thermal production in major plants
was concentrated in the two coal plant with 1 756MW and in the four natural
gas combined cycle plants with 3 289MW. With regard to production under the
special regime, the increase of almost 180MW by wind farms and 60MW by new
photovoltaic installations is of note.

2013 saw conditions which particularly favoured renewable energy production
with a productivity index of 1.17 in hydroelectric plants and 1.18 in wind farms.
In the case of wind farms, with 11 months above average, these were the most
favourable conditions ever seen on the national system. Under these conditions,
production from renewable sources reached 57% of the consumption, compared
to 37% in the previous year, a figure achieved in very unfavourable hydrologic conditions. Hydropower plants supplied 27% of consumption whilst wind plants supplied 24%, biomass plants 5% and photovoltaic plants 4%.

Coal fired plants maintained their usual share, supplying 22% of consumption,
while combined cycle natural gas plants accounted for only 3% of consumption
and cogeneration with non-renewable fuel, almost always natural gas,
accounted for 11%.

The import balance decreased to 6% of consumption, with the same thing
happening to export balances in the wettest periods of the year.

In 2013, 41.5TWh entered the transmission network, an increase of 1.2%
compared to the previous year. Losses amounted to 728GWh, equivalent to
1.76% of the incoming energy.

Demand and supply of natural gas

In 2013, the demand for natural gas totalled 47.9TWh, a reduction of 4.6%
compared to the previous year. This represents a third consecutive year of
a reduction in consumption, a drop of 17% in comparison with the historical
maximum achieved in 2010.

TWh Tradicional Market Variation Electricity
Variation Total
2009 29.5 4.7% 23.5 -7.3% 53.0 -1.0%
2010 35.5 20.5% 22.3 -5.1% 57.8 9.1%
2011 36.2 2.0% 21.3 -4.4% 57.5 -0.5%
2012 38.3 5.7% 11.9 -44.0% 50.2 -12.7%
2013 44.5 16.2% 3.4 -71.3% 47.9 4.6%

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This change in consumption can be attributed to the strong market downturn in
the production of electrical energy, corresponding to the four major combined
cycle plants that operate under the ordinary scheme that saw a 71% fall compared
to the previous year. This segment of the market corresponds to just 7% of overall
gas consumption, the lowest figure seen since 1998. The usage of available
capacity by these plants dropped to 4%, due to a lack of competitiveness
compared to coal and the exceptional conditions seen in the production of both
hydro and wind power.

The traditional market saw a large increase of 16%, reaching 44.5TWh, the
highest figure ever. This increase was due to the segment of clients on the high
pressure grid, with a 47% change resulting from new cogenerations that began
operating in 2012. In the distribution segment consumption was in line with the
previous year, whilst there was a 23% increase in clients supplied by autonomous
regasification units due to entry into service of new supply points.

In 2013, the interconnection points at Valença and Campo Maior accounted for
0.7% and 56.7% respectively of the supply necessary to satisfy national demand,
principally with gas originating from Algeria, whilst the remaining 42.6% were
provided by the LNG terminal at Sines and primarily originating in Nigeria.