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Assessment of legacy generation contracts' costs in the future Portuguese electricity system

Authors:
  • Center for Environmental and Sustainability Research (CENSE)

Abstract and Figures

Although the Portuguese electricity system liberalization process started almost 20 years ago, 83% of electricity generated in 2010 still benefited from a State guaranteed price, independent of market behavior. This applies not only to producers using renewable energy sources and cogeneration under feed-in tariffs, but also to all conventional power plants that undersigned a power purchase agreement in the 1990s. Because no comprehensive public information about State guaranteed prices is available, research was first carried out to unveil generation legacy contracts' volumes and then costs and their impact on consumers. A producers' database was created by the authors which enables an accurate assessment of the volumes of electricity with and without State guaranteed prices. In a previous paper the authors have validated the data set and the volume computation methodology for the period 2000-2010 and provided an estimate of those volumes in the period 2011-2030. This paper estimates average prices per producer type and assesses generation legacy contract costs in the period 2011-2030. Moreover, the paper computes the impact of generation legacy costs upon end-user average electricity prices and generation costs for several scenarios of market prices and demand.
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Assessment of legacy generation contracts’ costs in
the future Portuguese Electricity System
Filipa Amorim, Jorge Vasconcelos, Isabel Abreu, Patr´ıcia Silvaand Victor Martins§
IST, Technical University of Lisbon
APREN, Associac¸˜ao de Energias Renov´aveis
Faculty of Economics, University of Coimbra and INESCC
§ISEG, Technical University of Lisbon
Abstract—Although the Portuguese electricity system liberal-
ization process started almost 20 years ago, 83% of electricity
generated in 2010 still benefited from a State guaranteed price,
independent of market behavior. This applies not only to pro-
ducers using renewable energy sources and cogeneration under
feed-in tariffs, but also to all conventional power plants that
undersigned a power purchase agreement in the 1990s.
Because no comprehensive public information about State guar-
anteed prices is available, research was first carried out to unveil
generation legacy contracts’ volumes and then costs and their
impact on consumers. A producers’ database was created by the
authors which enables an accurate assessment of the volumes of
electricity with and without State guaranteed prices. In a previous
paper the authors have validated the data set and the volume
computation methodology for the period 2000-2010 and provided
an estimate of those volumes in the period 2011-2030.
This paper estimates average prices per producer type and
assesses generation legacy contract costs in the period 2011-2030.
Moreover, the paper computes the impact of generation legacy
costs upon end-user average electricity prices and generation
costs for several scenarios of market prices and demand.
Index Terms—Electricity, power systems, power generation
economics, contracts, feed-in tariffs
I. THE PORTUGUESE ELECTRICITY SYSTEM
The Portuguese electricity system has been under a restruc-
turing process towards full liberalization since the 1990’s, in
line with most of OECD countries and the European Union [1],
[2]. Fig. 1 presents a short overview of the main steps.
EDP
restructuring
1st Reform
1st Elect.
Directive
96/92/CE
2nd Elect.
Directive
2003/54/CE
3rd Elect.
Directive
2009/72/CE
2nd Reform
ERSE
1994 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 2010 …
Beginnig of
transition period
to extinguish
regulated
tarrifs
Full retail
competition
CMECs
definition
Step further
on retail
competition
PPAs
Fig. 1. Main steps in the restructuring of the Portuguese Electricity System
In 1994, the state-owned monopoly EDP was unbundled
according to its main business areas - generation, transmission
and distribution/supply - and became a group under the
operational and strategic coordination of the holding company
Grupo EDP.
The 1st legal reform of the national electricity system in 1995
provided for the co-existence of a regulated Public Electricity
System with a so-called Independent Electricity System [3]–
[8]. This reform called for the need of an independent regula-
tor, who entered into full operation in 1997, now designated
Entidade Reguladora dos Servic¸os Energ ´
eticos - ERSE.
In 2004, new legislation was approved that gave all electricity
consumers the right to choose supplier. Also in 2004, a
separate decree-law defined the compensation scheme (the so-
called CMEC regime) that provides the same financial return
and risk profile as the power purchase agreements (PPAs) [9].
The 2nd legal reform, in 2006, abolished the dual regime in
favor of the free market approach, in compliance with the
2003 Internal Electricity Market (IEM) directive [10]–[12].
Moreover, distribution was legally unbundled from supply and
a last resort supplier (LRS) was created. In the mean time,
ownership unbundling had been applied to the transmission
system operator and the retail market had been fully opened
to competition. In June 2007 generators established in Portugal
started bidding regularly into the Spanish/Iberian spot market.
In 2010, in compliance with the 2009 IEM directive, new
legislation was approved that foresees elimination of regulated
tariffs [13].
II. GENERATION MARKET STRUCTURE
Since the 2006 legislative revision [10], [11] generation is
divided in two regimes:
- Ordinary Regime (OR): conventional non-renewable ther-
mal sources and large hydro power plants;
- Special Regime (SR): renewables (except large hydro),
waste and cogeneration.
The OR is composed by the previous incumbent EDP, which
remains the country’s largest electricity generator, with power
plants under CMEC regime and some additional thermal and
hydro units without any price guarantees, operating on a free
market basis; also by the two thermal independent power
producers (IPPs), Tejo Energia (Pego) and Turbog´as (Tapada
do Outeiro), who have kept their PPAs; and by the 2010/2011
new plant of Elecg´as (Pego II).
The SR is composed by a myriad of players using different
technologies and belonging to several promoters with different
market shares [14]. SR generators sell their output at the
so-called feed-in tariff, for a certain period of time, varying
according to the technology and to the applicable regime.
In principle, electricity generation should be subject to
competitive pressures. However, PPAs, CMECs and SR
incentive system represent a considerable anti-competitive
legacy. This means that the revenues of most generators,
instead of varying according to market prices, are based on
previously established and guaranteed prices.
Table I shows total installed capacity and production per
technology, with and without State guaranteed prices, at the
end of 2010 [15]–[22]. Out of a total of 18 GW installed
capacity, 14,6 GW (82%) have a guaranteed price independent
from market conditions: 6 GW (34%) corresponds to feed-in
tariffs; 4,5 GW (25%) corresponds to the 2 remaining PPAs
and CMECs for thermal plants; 4,1 GW (23%) corresponds to
large hydro CMECs. Similarly, out of 52,2 TWh of electricity
available for consumption in 2010, 43,1 TWh (83%) have
a guaranteed price independent from market setting: 17,9
TWh (34%) from feed-in tariffs; 11,6 TWh (22%) from the 2
remaining PPAs and thermal CMECs, and 13,5 TWh (26%)
from the hydro CMECs.
TABLE I
INSTALLED CAPACITY AND PRODUCTION IN 2010
Installed Capacity GW % Production TWh %
Ordinary Regime 12.0 66% Ordinary Regime 32.1 62%
Hydro (CMEC) 4.1 23% Hydro (CMEC) 13.5 26%
Hydro (Free) 0.5 3% Hydro (Free) 1.3 3%
Thermal (PPA/CMEC) 4.6 25% Thermal (PPA/CMEC) 11.6 22%
Thermal (Free) 2.8 16% Thermal (Free) 5.7 11%
Special Regime 6.1 34% Special Regime 17.9 34%
NRES CHP 1.1 6% NRES CHP 4.4 9%
RES CHP 0.3 2% RES CHP 1.7 3%
Biomass (BM) 0.1 1% Biomass 0.6 1%
Biogas (BG) 0.03 0% Biogas 0.1 0%
MWS & IR 0.1 1% MWS & IR 0.5 1%
Small hydro 0.4 2% Small hydro 1.4 3%
Wind incl. overequip. 3.9 22% Wind incl. overequip. 9.0 17%
PV 0.1 1% PV 0.2 0%
Total 18.1 Domestic Production 50.1 96%
Import Balance 2.6 5%
Hydro Pumping 0.5 1%
Total Demand 52.2
NRES CHP: non-renewable cogeneration; RES CHP: renewable cogeneration; MWS & IR:
municipal waste sewage and industrial residues; PV: photovolataics
Table II presents targets to be put in place in order to allow
the electricity sector to achieve 60% renewable electricity
production by 2020 [23], [24].
TABLE II
SR CAPACITY ROADMAP FOR 2020
Capacity Wind
Onsh
Wind
Offsh
BM BG CHP
RES
Waves Conc.
Solar
Solar
PV
Geo. S.
hydro
CHP
NRES
MW 6.800 75 250 142 560 250 500 1.000 75 750 1.690
From Tables I and II it can be seen that the wind sector,
which represented 64% of SRP in 2010, will uphold its
preponderance in the SRP mix and achieve 6.875 MW of
installed capacity by 2020 (8% annual average increase). For
non-renewable CHP, which represents the second technology
in the SRP mix (18%), an annual average increase of 5% is
expected. For solar, which represented merely 2% of SRP in
2010, the plan foresses an annual average growth rate of 113%,
thus becoming the third most important source in the SRP mix
in 2020. Solar technologies 2020 goals were subdivided into
their different types and goals as follows: concentrated solar,
which includes concentrated photovoltaic (CPV) aimed at 240
MW and concentrating solar power (CSP) aimed at 260 MW
in 2020; photovoltaics, which include mini-generation aimed
at 500 MW, micro-generation aimed at 250 MW and large
scale applications aimed at 250 MW.
III. EXPECTED GENERATION LEGACY COSTS
In a previous paper the auhtors have estimated the expected
yearly production volumes by technology for the period 2011-
2030, considering the goals established in the National Renew-
able Energy Action Plan (Table II), along with those expected
additions and retirements of capacity foreseen by the system
operator until 2020 [23], [25]–[27]. Based on this work, after
definig future demand scenarios (DS) [28], it was possible to
compute the amounts of electricity generated every year with
and without State guaranteed prices.
Fig. 2 shows the amounts of electricity generation necessary
to cover total electricity demand under DS1 - i.e., assuming
that, for each power plant, at the end of the guaranteed price
period, the respective capacity would vanish, making room for
a competitive wholesale market. As it can be observed in Fig.
2, in 2020, 67% of electricity demand will be paid through
State guaranteed prices (35% to RES, 10% to non-renewable
CHP, 9% to hydro CMECs and 13% to thermal PPA/CMECs),
while merely 33% of electricity demand will correspond to a
free market price. In 2025, this trend should be reversed, with
67% of the electricity demand paid through free market prices
and 33% through State guaranteed prices (21% to RES, 10%
to non-renewable CHP and 1% to hydro CMECs).
26%
31%
35%
21%
15%
9%
9%
10%
10%
10%
26%
12%
9%
1%
22%
31%
13%
17%
16%
33%
67%
75%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Market
Thermal
PPA/CMEC
Hydro CMEC
NRES
RES
Fig. 2. Electricity generation mix relative to demand
When DS2 is used a maximum variation of 2% for RES
sources and of 1% for all other sources can be observed.
Simplified cost functions have been used to estimate annual
costs associated with guaranteed SRP, per technology, accord-
ing to the applicable legislation. The assumptions used are
summarized in Table III for renewables and waste sources and
in Table V for cogeneration.
SR feed-in tariffs have not been listed explicitly in the wording
of the law and they are actually calculated monthly for
each plant based on the avoided costs concepts. Common
determinants of tariffs are the technological efficiencies, which
directly relate to the primary energy used; the day/night time
of delivery of power to the grid and inflation rates. In the
case of non-renewable CHP, remuneration is also heavily
dependent on the primary energy fuel costs, dependent, in
turn, upon international oil prices and exchange rates. In
the case of renewable CHP, fuel costs will only influence
total remuneration in proportion to the complementary non-
renewable fuel needed.
TABLE III
RENEWABLESAND WASTE SIMPLIFIEDANNUAL COSTS ASSUMPTIONS
Technology DL 339-C/2001 DL 33-A/2005 DL 225/2007 Tender+
Wind Onsh. 97e2009/MWh 73.4e/MWh Phase A and B:
if Hrs.<2.000a97e/MWhb
92e2009/MWh Phase C:
if 2.000<=Hrs.<2.600a73.4e/MWhb
88e2009/MWh
if Hrs.>=2.600a
Small hydro 85e2009/MWha93e/MWh
MWS IR 72.4e2005/MWha
Biomass 109e/MWhb109e/MWhb109e/MWhbe
Biogas 109e/MWhb109e/MWhb
Solar PV 320e2005 /MWh 320e/MWhbPV:257e/MWhb
Micro:400e/MWhbc
Micro:250e/MWhbd
Solar Conc. 273e/MWhbCPV:380e/MWhb
Waves 200e/MWhb
Wind Offsh. 73.4e/MWhb
aValue updated with inflation; bValue at the beginning of activity updated with inflation from then on
cwith reductions of 20 /MWh/y dwith reductions of 7%/y. +Tenders were introduced for wind onshore
in 2005/2006 (phase A and B) and 2008 (phase C);for small hydro DL 126/2010 applies; for biomass
DL 5/2011 applies; for solar mini-generation DL 34/2011 applies; for solar micro-generation
DL 118-A/2010 applies; for CPV DL 132-A/2010; for CPV MO 1057/2010 applies.
ePlants entering into function before 2013 will change the rules of their feed-in tariff calculation by then.
Despite DL 5/2011 only applies to plants entering into function until 2014, it was considered that plants
entering into function after 2014 will also benefit from the new rule.
Before 2001, all electricity generation based upon renewable
and waste sources was paid feed-in tariffs according to the
formulas in DL 168/1999. From 2002 on, tariffs have been
calculated according to the figures in Table III, differentiated
by technology type. When DL 339-C/2001 applies, tariffs
are set at a given price, which is continuously updated with
inflation. In the particular case of wind, those values depend
on the wind parks’ efficiencies, i.e., on the average number of
hours the park is functioning per year. When DL 33-A/2005,
DL 225/2007 or tenders apply, tariffs are fixed at a given
value at the date of entering into function of the plant which,
from then on, is updated with inflation. This amendment with
inflation updates encourages projects to enter into function
as early as possible in order not to lose the money value of
inflation. Since 2006, tenders for the licensing of new wind
and biomass projects have been carried out by the government,
meaning that producers accept a pre-defined discount to the
entitled feed-in tariff in place. In phase C of wind tenders,
discounts depended on each producers’ bid offers per lot, as
described in Table IV. More recently tenders have also been
launched for solar pilot projects. Tenders referred in Table III
correspond to specific legislation depending on the technology.
Before 2002, cogenerators have been paid feed-in tariffs cal-
culated according to the formulas referred to in DL 538/1999.
From 2002 on, tariffs have been calculated based on different
TABLE IV
DISCOUNTS TO THE WIND FITS(%) IN TENDER PHASE C
Lots 12345678910111213
Discounts 15.76 20.23 20.2 22.5 23.15 5.52 19.71 5.15 7.01 10.5 20.02 8.5 20
conditions as shown in Table V. In the case of renewable
CHP, assuming a very diminutive weight of the complimentary
non-renewable energy source in the co-generation process and,
therefore, a similar reasoning to that in Table III, a given value
was set (91e/MWh) at the date of entering into function of
the plant updated with inflation from then on. In the case
of non-renewable CHP, irrespectively of the particular regime
applied, tariffs have been calculated for each producer based
on their common formulas as if they were a virtual plant,
representative of all the installed plants. This virtual power
plant was considered to have natural gas as the dominant fuel;
to run an average of 6.000 hrs/year and to have an equivalent
electrical efficiency of 60-65%.
TABLE V
CHP SIMPLIFIEDANNUAL COSTS ASSUMPTIONS
MO57/2002 MO58/2002 MO59/2002 MO60/2002
RES CHP 91e/MWh/a
NRES CHP Virtual plant
aValue at the beginning of activity updated with inflation from then on.
Historical SR average guaranteed prices have been calcu-
lated and verified against available public data. Results are
shown in Fig. 3 where deviations between calculated average
costs and those verified, as published by ERSE [29], are
depicted.
3,2%
4,7%
0,2%
3,6%
4,7%
4,9%
4,5%
1,6%
0,4%
1,2%
3,0%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Other Cogen RES Cogen Wind OnS Small hydro MWS Biomass Biogas Solar PV Total SRP
Fig. 3. Deviation of average SRP costs in the model
Major deviations (>15%) are observed in two cases: in 2002
for biogas and in 2005 for solar PV technologies; in both
situations these technologies represent a very small share of
the electricity mix (see Table I). Deviations between 5 and
15% are more frequent for non-renewable CHP and biogas
technologies in the period 2003-2006, probably because it
is difficult to capture verified thermal production variations.
Average SRP cost deviations are lower than 5% for the whole
period 2000-2010. Therefore, the results of the simplified
model developed can be seen as a fairly good approximation
for the purpose of cost assessment.
The same simplified cost model was used to estimate indi-
vidual annual costs in the period 2011-2030 for SR plants
connected to the grid at the end of 2010 (installed) and for
those SR plants with licenses assigned by then, but not yet
built or functioning (contracted). The costs for the planned
SR capacity not yet licensed have been computed according
to the 3 following assumptions presented in Table VI:
- Scenario A, worst case scenario, where the cost functions
of already installed plants are used (i.e., no efficiency
gains considered);
- Scenario B, medium case scenario, where all planned
solar capacity accomplishes 5%/year costs reductions;
- Scenario C, best case scenario, where in addition to
Scenario B, planned non-solar capacities accomplish a
2%/year costs reductions.
Solar capacities (mini and micro generation along with
CPV) in addition to biogas are those farther from accomplish-
ing what is planned. Biomass, large scale PV applications,
wind and small hydro are those in which none or few MWs
remain to be contracted.
In the same period 2011-2030, lower and upper prices of
60 and 100 e/MWh, respectivley, have been considered for
PPA/CMEC generators. Lower bound prices represent Sce-
nario 1 and upper bound prices represent Scenario 2. These
values have been chosen based on the observed average final
PPA/CMEC prices in the period 2000-2010, as depicted in
Fig.4. These are the prices actually received by producers,
except those for 2010, which are still provisional [15]–[20],
[30]–[32] - i.e. after taking into account all differences be-
tween forecasts included ex ante in the regulated tariffs for
year tand ex post adjustments made in years t+1 and t+2,
based on actual data, and excluding hydrological corrections.
y = 3,1588x + 42,677
R² = 0,4566
40
50
60
70
80
90
100
110
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
PPA/CMEC average unit cost ( /MWh)
Fig. 4. PPA/CMEC average unit costs
The 6 scenarios resulting from different combinations of SR
and PPA/CMEC cost assumptions are described in Table VI.
Fig. 5 summarizes total legacy generation costs in the period
2011-2030, considering all 6 scenarios combining estimates
of the average annual State guaranteed prices (Table VI) and
annual generation volumes (Fig. 2). In Figs. 5(a), 5(c) and 5(e),
total costs for each year are presented in each particular
scenario, while Figs. 5(b), 5(d) and 5(f) represent a zoom in
yearly costs in some particular scenarios.
TABLE VI
LEGACY GENERATION COSTS SCENARIOS IN PERIOD 2011-2030
Scen. Cost function applied Scen. Annual average unit Scen.
to SR planned capacity costs with PPA/CMEC
A1 Table III A lower bound in Fig. 4 1
A2 upper bound in Fig. 4 2
B1 Table III while B lower bound in Fig. 4 1
B2 all solar tech. 5%/y efficiency upper bound in Fig. 4 2
C1 Table III while lower bound in Fig.4 1
all tech. except solar 2%/y C
C2 all solar tech. 5%/y efficiency upper bound in Fig. 4 2
Aggregated total generation legacy costs present a higher
absolute peak in 2017, which matches the expected termination
of considerable amount of thermal PPA/CMEC contracts (see
Fig. 2), and a second relative higher peak in 2020, which
matches the RES total costs absolute peak. In 2020, aggregated
costs will rise to 3.556 M e2011 in the best case (Scenario
C1), and to 4.362 M e2011 in the worst case (Scenario A2).
In the same year 2020, RES generation legacy costs will
amount to 2.029 M e2011 , under Scenario C, and to 2.231
Me2011, under Scenario A, while NRES generation legacy
costs will amount to 688 M e2011 , under Scenario C, and to
733 M e2011 , under Scenario A. The possible costs reductions
in 2020 due to 5%/y costs reductions in solar technologies
(Scenario B) may ascend to 126 M e2011 savings whether
the 2%/y costs reductions in all other technologies (Scenario
C) may represent additional savings of 120 M e2011 . Finally,
in 2030, best and worst case scenarios (Scenario C and A,
respectively) only depend on SR costs, as PPA/CMEC totally
disappear in 2025. Aggregated costs may ascend to 1.424 M
e2011 and 1.838 M e2011 , in each of those cases, with more
than 50% of costs due to RES costs and the rest due to NRES
costs.
IV. END-USER AVERAGE ELECTRICITY PRICES
Independently of the supplier they choose, end-users must
support all legacy costs. Therefore, end-user average electricity
price is the price a final consumer will have to pay on average
for all electricity consumed in the system. This electricity can
originate either from SR producers, paid by feed-in tariffs (p1),
or from plants under PPA/CMEC, paid through those contracts
(p2), or from producers trading in the free market place, paid
through the market price (p3), as described in Eq. 1 below.
penduser =d1×p1+d2×p2+d3×p3
d1+d2+d3
(1)
Where,
penduser - Average annual end user price
p1- Guaranteed SRP annual average price
p2- Guaranteed PPA/CMEC annual average price
p3- Annual average market price
d1- SRP electricity annually consumed in the system
d2- PPA/CMEC electricity annually consumed
d3- Free market electricity annually consumed
Considering 5 different possible market prices (p3)-
namely, 60 e2011/MWh, 70 e2011 /MWh, 80 e2011/MWh,
1.500
2.000
2.500
3.000
3.500
4.000
4.500
5.000
5.500
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Aggregated legacy costs (M 2011)
A2
B2
C2
A1
B1
C1
AVRG
(a) Aggregate
3.801
4.810
3.556
4.116
1.870 1.894
1.424 1.424
24
24
120
120
194 194
223 223
24
24
126
126
192 192
191 191
0
500
1.000
1.500
2.000
2.500
3.000
3.500
4.000
4.500
5.000
12121212
2015 2020 2025 2030
Aggregated legacy costs (M 2011)
A
B
C
(b) Aggregate
0
500
1.000
1.500
2.000
2.500
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
RES legacy costs (M 2011)
A
B
C
AVRG
(c) RES
1.696
593
2.029
688
1.135
699 745 679
13
11
76
44
121
73 131 92
24
0
126
0
192
0191 0
0
500
1.000
1.500
2.000
2.500
RES NRES RES NRES RES NRES RES NRES
2015 2020 2025 2030
RES & NRES legacy costs (M 2011)
A
B
C
(d) RES and NRES
0
100
200
300
400
500
600
700
800
900
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
NRES legacy costs (M 2011)
A
B
C
AVRG
(e) NRES
1.513
2.521
839
1.398
36 60 000
500
1.000
1.500
2.000
2.500
3.000
12121212
2015 2020 2025 2030
PPA/CMEC legacy costs (M 2011)
A/B/C
(f) PPA/CMEC
Fig. 5. Total legacy costs
90 e2011/MWh and 100 e2011 /MWh - alongside State guar-
anteed prices (p1and p2) under the worst case scenarios
(scenarios A), the average end-user price (penduser) may
vary each year according to what is depicted in Fig. 6(a)
(Scenario A); while Fig. 6(b) represents the top contour values
of those intervals (Scenario A2). Fig. 6(b) shows that if the
market price (p3)is60e2011/MWh, the end-user average
price (penduser ) may vary between 72 e2011/MWh in 2030
and 95 e2011/MWh in 2011. This means the end-user average
price (penduser ) will be considerably higher that market price
(p3) and hence consumers will be paying an average price
much higher than that found in the market. If the market
price (p3) is set to 80 e2011/MWh, the end-user average price
(penduser ) may vary between 97 e2011 /MWh in 2011 and
87 e2011/MWh in 2030, and a similar conclusion of excessive
cost to consumers given State guaranteed prices can be drawn.
If the market price is 100 e2011/MWh, the end-user average
price (penduser ) may vary between 100 e2011 /MWh in 2011
and 102 e2011/MWh in 2030. This case means the end-user
average price will be equal to market price in 2011 and in
2015, the case consumers will, hence, be paying an average
price similar to that found in the market. For the rest of the
years presented in the figure, a maximum 2e2011/MWh extra
cost can be found.
Fig. 7(a) shows the worst case scenario A2 from another
perspective. Thicker lines correspond to end-user average
prices (penduser ) given a market price (p3), while thinner
lines represent those market prices (p3). Colours in the legend
continue to be used for each market price as in Fig. 6. When
one colour thicker line crosses the thinner line in a given
year, this means that in that year, end-users are indifferent
to buy electricity in the market or to pay it through the State
guaranteed price mechanisms in place. In the subsequent year,
if the average market price (p3) will be higher than end-user
average price (penduser ) this means that the end-users start
then to benefit from the State guaranteed price mechanisms
in place as these become cheaper than market prices. On the
contrary, if the average market price (p3) becomes lower than
end-user average price (penduser ) this means that the end-
users start then to be prejudiced from the State guaranteed
price mechanisms in place as these become costlier than
market prices. In Fig. 7(a) one can see again that when the
market price is set to 60 or 70 or 80 or even 90 e2011/MWh
thicker and thinner lines do not cross at all. Only when market
price is set at 100 e2011/MWh those thicker and thinner lines
decouple from 2019 on. Until 2019, State guaranteed prices
will be indifferent to market prices. After 2019, consumers
should prefer to buy electricity in the market as this would
enable 2e2011/MWh/y savings.
Fig. 7(b) similarly shows the best case scenario C1. Only when
the market price (p3) is set to 80 e2011/MWh thicker and
thinner lines cross. Before the year 2017 consumers will prefer
to pay electricity through State guaranteed prices. After 2017,
this preference is reversed.
For all the 6 scenarios of State guarenteed prices (p1
and p2), the indifference price curve lines in which end-user
average price (penduser) equals average market price (p3), as
synthetized in (Eq. 2), are illustrated in Fig. 8.
(Eq. 2) shows that the equality between average end-user and
market prices is independent of total electricity demand (d3),
while Fig. 8 shows that consumers may expect to benefit from
State guaranteed prices until 2020 if the average market price
(p3) exceeds 80 e2011 /MWh under scenarios 1 (A1, B1, C1)
or 95 e2011/MWh under scenarios 2 (A2, B2, C2).
pend-user =p3=d1×p1+d2×p2
d1+d2
(2)
Fig. 9 summarizes the price intervals including all consid-
ered scenarios represented in Fig. 8, bounded by the lower
and higher cases - Scenarios C1 and A2, respectively. Fig. 9
shows that until 2020, the average indifference price is around
90 e2011/MWh (the mean average of each year interval). From
2020 on, this average indiference price increases and comes
close to 95 e2011/MWh.
60 70 80 90 100
2011
2015
2020
2025
2030
70
80
90
100
110
2011/MWh
2011/MWh
(a) Scenario A
2011
2011
2011
2011
2011
2015
2015
2015
2015
2015
2020
2020
2020
2020
2020
2025
2025
2025
2025
2025
2030
2030
2030
2030
2030
0
20
40
60
80
100
60 70 80 90 100
End-user prices A2 ( 2011/MWh)
Market prices ( 2011/MWh)
(b) Scenario A2
Fig. 6. End-user price intervals for possible market prices
60
65
70
75
80
85
90
95
100
105
110
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
End-user price A2 ( 2011/MWh)
Pend-user
(P3 100 2011/MWh)
Pend-user
(P3 90 2011/MWh)
Pend-user
(P3 80 2011/MWh)
Pend-user
(P3 70 2011/MWh)
Pend-user
(P3 60 2011/MWh)
(a) Scenario A2
60
65
70
75
80
85
90
95
100
105
110
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
End-user price C1 ( 2011/MWh)
Pend-user
(P3 100
2011/MWh)
Pend-user
(P3 90 2011/MWh)
Pend-user
(P3 80 2011/MWh)
Pend-user
(P3 70 2011/MWh)
Pend-user
(P3 60 2011/MWh)
(b) Scenario C1
Fig. 7. Evolution of end-user average price
V. E ND-USER TOTAL ELECTRICITY COSTS
Total yearly electricity costs were computed for 2 demand
scenarios, 5 different market prices and all 6 above analyzed
50
60
70
80
90
100
110
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Indifference pric e curves ( 2011/MWh)
PA2 PA1
PB2 PB1
PC2 PC1
Fig. 8. Indifference price curves under all 6 scenarios
70
75
80
85
90
95
100
105
110
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Indifference price intervals
p3=pend-user (2011/MWh)
Fig. 9. Market price intervals within which it is indifferent for consumers
to buy electricity in the market and to pay Sate granted prices
legacy generation costs scenarios. Fig. 10 summarizes the
results for the cases of market prices (p3)of60e2011/MWh,
80 e2011/MWh and 100 e2011 /MWh.
In the case market price is 60 e2011/MWh, total yearly
generation costs range between 4.300 and 6.000 M e2011
within the period 2011-2030. The possibility of costs savings
due to the above mentioned costs reductions in all SR tech-
nologies are about 48 M e2011 in 2015 (24 M e2011 due
to 5%/y costs reductions in solar technologies and the other
24 M e2011 because of additional 2%/y costs reductions in
non-solar technologies), about 146 M e2011 in 2020, about
384 M e2011 in 2025 and about 414 M e2011 in 2030. Total
generation costs may ascend to near 6.000 M e2011 in 2020
in the worst case Scenario A2; in this case, total generation
legacy costs represent more that 75% of total.
If the market price is 80 e2011/MWh, total generation costs
may ascend to near 6.450 M e2011 in 2020 in the worst case
Scenario A2. If the market price is 100 e2011/MWh, total
generation costs may ascend to near 6.970 M e2011 in the
same case.
If market price is 80 e2011 /MWh, total generation costs
will range between 4.500 M e2011 and 6.600 M e2011 and
if market price is 100 e2011/MWh, total generation costs will
range between 4.700 M e2011 and 7.800 M e2011.
VI. CONCLUSIONS
This paper presents a methodology and a data set to
evaluate generation legacy costs in the Portuguese electricity
system. These generation legacy costs have two origins: PPAs
established in the 1990s and partially reviewed in 2007 and
feed-in tariffs granted to generation from renewable and waste
sources, as well as to cogeneration. The methodology and the
4.365
5.373
4.552
5.561
4.740
5.749
4.840
5.399
5.268
5.827
5.696
6.255
4.581
4.605
5.485
5.509
6.388
6.412
4.577
4.577
5.628
5.628
6.680
6.680
24
24
24
24
24
24
120
120 120
120 120 120
194 194
194 194
194 194
223 223
223 223
223 223
24
24
24
24
24
24
126
126 126
126 126 126
192 192
192 192
192 192
191 191
191 191
191 191
0
1.000
2.000
3.000
4.000
5.000
6.000
7.000
8.000
121212121212121212121212
60 80 100 60 80 100 60 80 100 60 80 100
2015 2020 2025 2030
Total generation costs under DS1 (M 2011)
A B C
(a) Demand scenario 1
4.475
5.483
4.700
5.708
4.924
5.933
5.121
5.680
5.643
6.202
6.164
6.723
4.938
4.962
5.960
5.984
6.983
7.007
5.017
5.017
6.214
6.214
7.412
7.412
24
24
24
24
24
24
120
120 120
120 120 120
194 194
194 194
194 194
223 223
223 223
223 223
24
24
24
24
24
24
126
126 126
126 126
126
192 192
192 192
192 192
191 191
191 191
191 191
0
1.000
2.000
3.000
4.000
5.000
6.000
7.000
8.000
9.000
121212121212121212121212
60 80 100 60 80 100 60 80 100 60 80 100
2015 2020 2025 2030
Total generation costs under DS 2 (M 2011)
A B C
(b) Demand scenario 2
Fig. 10. Total generation costs
data set were validated using publicly available historical data
(2000-2010). They were then used to forecast the absolute
value and the relative weight of legacy costs that will be paid
in the future by all electricity consumers.
This paper makes use of the present and future amounts of
electricity quantities, with and without State guaranteed prices,
that were computed in a previous paper by the same authors.
Based on detailed analysis of legislation and available data
from several sources, this paper further computes the yearly
average costs associated with these quantities and their weight
into final consumers energy prices in the period 2011-2030.
In 2020, 67% of electricity demand will correspond to
State guaranteed prices (35% RES, 10% non-renewable CHP,
9% hydro CMECs and 13% thermal PPA/CMECs); in other
words, only 33% of electricity demand will correspond to
a free market price. In 2025, this trend should be reversed,
with 67% of the electricity demand paid through free market
prices and 33% through State guaranteed prices. From a public
policy and regulatory point of view these considerable changes
within a short period of time require careful planning of a
coherent short and long-term market (re)design process with
well-defined transition stages.
Analysis of 6 different scenarios concerning the evolution of
generation costs show that for average market prices above 80
e2011/MWh consumers may benefit from the State guaranteed
prices currently in place within the period 2011-2030. This
assessment only considers prices actually paid to generators
and does not take into account factors like carbon pricing
and positive or negative side-effects of different generation
patterns.
The need to prepare the transition of market structures to
take into account the evolution of feed-in energy volumes is
not limited to Portugal. In fact, according to current estimates
by 2020 (see for instance [33]), renewables will account for
more than 40% of gross electricity consumption in more than
9 Member States and in 6 Member States wind and solar
alone will account for more than 25% of gross electricity
consumption.
ACKNOWLEDGMENT
This manuscript has been partially supported by FCT
(Fundac¸˜ao para a Ciˆencia e Tecnologia) under the grant
SFRH/BD/42988/2008 as part of the MIT Portugal Pro-
gram on Sustainable Energy Systems and grant PEst-
C/EEI/UI0308/2011.
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... Price guarantees represent costs to be paid by electricity consumers during the next decades. Based on the data provided in this paper it was be possible to estimate the evolution of legacy costs to be supported by electricity consumers in the future [49]. ...
... In what concerns the electricity sector, the expected installed capacity additions and retirements in the Portuguese electricity system up to 2020, based in the expectations built as of 2011, have been comprehensively described in Refs. [49,54]. Some of these investments are still currently being re-scheduled, others re-defined, while considerable uncertainty still persists within the possible evolutions of the sector. ...
Technical Report
Full-text available
The European Union has the target to increase the share of renewable energy sources (RES) in its gross final consumption of energy to 20% by 2020 (9.2% in 2006). Besides electricity, primary energy consumption includes heating, cooling, and transportation. Increasing RES in transportation is more costly than in electricity generation, and hence the share of renewable energy sources in electricity generation is likely to be significantly higher than 20%. It has been estimated, that the RES share in electricity sector could be around 35% in 2020. A significant part of the new renewable electricity (RES-E) capacity will be wind power and photovoltaics (PV). The output from these is variable, and not dispatchable in the traditional sense. Increasing wind and PV generation presents vast challenges to the power market and electricity grid. The keys to integrate variable generation to the grid are adequately interconnected electricity markets and smarter grids with more flexible demand. Currently, each Member State has a separate support scheme for RES-E. The instruments can be divided between investment support and operating support (price subsidies, green certificates, tender schemes, and tax reductions for the production of electricity). Feed-in tariffs are the most prevalent support mechanism. Largest addition in the NREAPs is expected from wind power generation. Wind power could exceed hydropower generation in 2016-2017. High growth is also expected in solid biomass-based electricity generation and PV. NREAP scenarios were compared against four other sources, which had quite similar expectations.
Article
This paper discusses the spread of electricity deregulation in OECD countries since the early 1990s. England, Wales and Norway were the pioneers, but almost all OECD countries have now introduced some degree of liberalisation, and several have free entry to generation while allowing all electricity consumers to choose where they buy their power. The paper discusses some of the issues raised by competition in generation and in retailing (or supply), and the need to have appropriate regulation for the transmission and distribution systems, which will continue to be monopolies.
National Renewable Action Plan -Portugal
  • Government
Government of Portugal, "National Renewable Action Plan -Portugal," Oct. 2010.
InformaçInformaç˜Informação sobre produçproduç˜produção em regime especial (PRE) em Portugal continental-Dez
  • Erse
ERSE, "InformaçInformaç˜Informação sobre produçproduç˜produção em regime especial (PRE) em Portugal continental-Dez. 2010," 2011.
Novas barragens -centros produtores | EDP -viva a nossa energia
EDP, "Novas barragens -centros produtores | EDP -viva a nossa energia," 2010.
Proveitos permitidos das empresas reguladas do sector eléctrico em
  • Erse
ERSE, "Proveitos permitidos das empresas reguladas do sector eléctrico em 2009," 2008.
Dados técnicos da REN
REN, " Dados técnicos da REN 2009, " 2010.
Programa nacional de barragens com elevado potencial hidroeléctrico (PNBGPH)
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INAG and DGEG, " Programa nacional de barragens com elevado potencial hidroeléctrico (PNBGPH), " http://pnbeph.inag.pt, 2007.
O sector eléctrico em Portugal continental
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