Report with the scope of measure 5.15 of the second

regular review of the Memorandum of Understanding on

Specific Economic Policy Conditionality

9th of February 2012

1

Contents

1. INTRODUCTION ....................................................................................................................... 2

2. BACKGROUND ......................................................................................................................... 3

3. TARIFF DEFICIT GROWTH ...................................................................................................... 4

4. MEASURES DISCUSSED WITH PRODUCERS ........................................................................... 5

4.1. REGULATION OF CURRENT COGERAÇÃO LAW ............................................................ 5

4.2. REVISION OF CMECs ANNUITY ....................................................................................... 6

4.3. EXTENSION OF THE F.I.T. (FEED-IN-TARIFF) PERIOD IN WIND FARMS ................... 7

4.4. SALE OF CO2 LICENSES ................................................................................................... 7

4.5. IMPACT OF APPLICATION OF DISCUSSED MEASURES IN THE EVOLUTION OF THE

TARIFF DEFICIT ........................................................................................................................ 8

5. ADDITIONAL MEASURES TO BE NEGOTIATED WITH PRODUCERS ..................................... 9

5.1 POWER GUARANTEE MECHANISM ................................................................................. 10

5.2. RENEGOTIATION OF COGERAÇÃO .............................................................................. 11

5.3. RENEGOTIATION OF CAEs ............................................................................................ 12

5.4. RENEGOTIATION OF CMECs ......................................................................................... 12

5.5. OTHER RENEWABLES .................................................................................................... 12

6. CONCLUSION ......................................................................................................................... 13

ANNEX: EFFECTIVE RATES OF RETURN .................................................................................. 14

2

1. INTRODUCTION

Energy Policy in the last decades was marked by the opening to private (and

international) participants and by the promotion of renewable energy. This

was pursued through mechanisms that incentivize producers. The costs

associated to those incentives paid to electricity generators (included in the

so-called CIEG’s - Economic General Interest Costs) are transferred to the

electric system through the access tariff and, therefore, to electricity

consumers.

Provisional evolution of regulated and liberalized costs (Bn€)

At the end of 2011, the tariff deficit was 1750 M€ and during 2012, an

additional 1080 M€ is expected to be added so as not to further increase the

already hefty burden on families and industry (bearing in mind that we have

raised VAT from 6 to 23% in October 2011 and introduced excise tax on

electricity, and, on top of which a 27% price increase would be added).

In light of this, and as agreed upon in the Memoranda of Understanding signed

between Portugal and ECB/EC/IMF, there is a need to assess the overall status

and sustainability of the NES and take measures in order to set it on a

sustainable path leading to the elimination of the tariff deficit until 2020.

This reports assesses the current status of the NES, presenting the

approximate value of the returns that generators of electricity obtain, and

presents a set of actions that can be divided between i) measures already

discussed with producers and ii) other measures that will be introduced in

further negotiations.

2013E

7,1

1,1

2,6

2012E

7,3

1,4

1,9

2011

6,2

1,5

1,5

+18%

2020E

7,9

4,5

8,1

2018E

7,7

4,8

2019E

4,3

2017E

7,4

+2,3% pa

0

-1,9% pa

10

8

6

4

2

0,4

3,5

2014E

7,0

3,1

0,7

3,04,0 4,0

2015E

7,1

2016E

7,3

4,0 3,4 3,2 3,2 3,3 3,43,4

3,4 3,3

Energy & Comercialisation (liberalized) Energy & Comercialisation (regulated)Access Tariff

Previsional evolution of regulated and liberalized costs (mM€)

3

2. BACKGROUND

The generation business in Portugal can be divided in two main regimes: 1)

Ordinary Generation (PRO) and 2) Special Generation (PRE)

A. PRO

― CAEs (Purchasing Power Agreements): In force since the 90’s, the

remaining two CAE’s (600 MW coal power plant and 1000 MW CCGT

power plant) benefit from pre-established profitability (provided in the

context of an international tender), which is independent from the

effective generation of the power plants (quantity risk-free) and from

fuel costs (price risk-free); additionally, there is an incentive (or a

penalty) depending on the relation between real and contractual

availability and the producer bears design, construction, maintenance

and financing risks. The CAEs appeared back in the mid-90s as a

response to the objective of the Government to open electricity sector

to private initiative while aiming to build additional generating

capacity in the country. In this context, international tenders were

launched where the State agreed to buy energy in return for a pre-

established return to generators – thus emerging the CAEs which were

attributed to Tejo Energia and Turbogas with a majority of share

capital belonging to international energy players. Following these

tenders and with a view to facilitate EDP’s privatization and access to

international financial markets, a similar CAE was signed with EDP;

― Costs of Maintenance of the Contractual Equilibrium (CMECs): Given

that most of the electricity generated in the Portuguese market was

subject to long term CAEs and given the European and Portuguese goal

of establishing a fully functioning MIBEL, the Portuguese Government

needed to bring forward the ending of the pre-existing CAE’s. To this

end and given the importance of maintaining respect for the “rule of

law” a voluntary transitional system was designed to lead CAE contract

owners into the MIBEL. This created the CMECs. In force since July 2007

and regulated by Decree-Law 240/2004, of December 27th, which sets

the rules for the early termination of the CAEs, this mechanism is

applied to a set of power plants (currently a1180 MW coal power plant,

a 940 MW fuel-oil power plant and 26 large hydro power plants with a

total installed capacity of 4100 MW) which sell generated electricity in

the market and benefit from a compensation that was designed to

correspond to the difference between the market obtained income and

the one that would be obtained under CAE regime, thus intending to

ensure financial neutrality between the former CAE and the new CMEC

contract; also in this case, asset remuneration is guaranteed and is

independent from market income; It should be noted that all the CMEC

4

power plants belong to EDP, as all other investors with CAE opted out

of the proposed CMEC deal;

― Other: The remaining PRO generating capacity (currently, 3 CCGT

power plants: 1175 MW + 830 MW + 830 MW; and a large hydro power

plant: 240 MW) benefit from power guarantee mechanism, justified by

a contribution that they provide to security of electricity supply.

B. Renewable PRE

― Generation plants using renewable energy sources, benefit from

dispatch priority (grid reception of the generation is guaranteed) and

from a pre-established feed-in tariff (remuneration scheme that

guarantees a fixed purchasing price along the major part of the

operating lifetime – typically first 15 years); There are around 500

renewable PRE power plants, corresponding to an installed capacity of

6000 MW;

― Cogeração (Combined heat and power - CHP)

Cogeração benefits from a guaranteed remuneration for the total

electricity generation (including generation for self-consumption),

which is based on the “avoided costs” methodology and is immune to

inflation rate, oil price and currency variations; There are around 160

Cogeração power plants for an installed capacity of 1550 MW.

3. TARIFF DEFICIT GROWTH

In order to better understand the nature, expected evolution, assess the

sustainability and reach a common understanding of the current tariff deficit

situation, efforts have been made by the Ministry of Economy along with

players in the generation market to develop a model that would describe the

NES and the tariff deficit.

The model provides an estimate on the evolution of the NES up to 2020.

The base case we have built illustrates how the tariff deficit would evolve in a

“no policy change” scenario, with real end-consumer price increases between

1,5 and 2,0% per annum (aligned with the sustainability of the prices of

energy that will help foster the economy’s competitiveness) and average

hydrological conditions.

5

Evolution of the tariff deficit (Bn€)1

1 Average annual price growth of 1,85%/year

The model shows that, with no policy change, the tariff debt will increase

until 2016, up to 4,8 Bn€. In 2020, the remaining debt is 3,6 Bn€.

4. MEASURES DISCUSSED WITH PRODUCERS

To tackle the growth of tariff deficit, a set of measures have been identified

in the context of the discussions already held with the suppliers.

4.1. REGULATION OF CURRENT COGERAÇÃO LAW

The Decree-Law No. 23/2012 of March 25, amended by the Law 19/2010 of

August 23, defined two remuneration schemes for combined heat and power

generation (Cogeração).

- The general regime, in which Cogeração installations are paid on the

basis of organized market or bilateral contracts, receiving in addition a

market premium;

- The special regime, under which the facility is paid through a feed-in-

tariff, plus an added reference efficiency premium and a bonus for

renewable energy, according to the proportion of renewable energy

sources consumed at the plant. In this scheme, the cogenerator is paid

by the total electric energy produced during the first 120 months after

the start of operation; based on a revised reference tariff, this period

can be extended by the General Directorate for Energy and Geology

(DGEG) for 120 months per the request of the cogenerator, provided

that the classification of efficient or highly efficient Cogeração is

Evolution of the tariff debt (mM€) – Average real price growth: 1,85%/year 1

5

4

3

2

1

0

2020E

3,0

2019E

0,7

2018E

0,8

3,8

2017E

0,9

4,7

2016E

1,1

4,8

2015E

1,2

4,6

2014E

1,4

4,3

2013E

1,5

3,8

2012E

1,6

20112010

1,9

2,9

3,6

3,83,7

4,6

4,3

3,6

2,9

1,8

0,6

1,9 1,8

1,2

2,3

3,4

Existing debt

New debt

1 Average annual price growth that allows, together with the measures discussed with the producers, the elimination of the new debt until 2020

6

maintained. For operations with installed capacity of 20 MW or less, the

tariff shall be reviewed taking into account the depreciation of 1% per

year, while for the remaining facilities this tariff is reduced by 17%.

Note that this tariff reduction does not include renewable Cogeração,

which have no rate reduction.

The remuneration for the general case is based on the selling price in an

organized market or bilateral contract and a market premium, which takes

the value of 50% of the reference tariff corresponding to the cogeneration

plant.

A transitional regime for existing Cogeração plants is envisaged, allowing that

the current remuneration conditions may be kept until they reach 180 months

after their commissioning date or 120 months after the Decree-Law had

entered into force, whichever date occurs first. After this time, Cogeração

plants will get into the new regime, until it completes 240 months of

operation. The transition to the new remuneration regime is accompanied by

certification EEGO (Cogeneration Guarantee of Origin Certification Body).

The values of the reference tariff for the special regime, the formulas to

update it in the future, the efficiency premium and the renewable bonus are

to be defined by Ministerial Ordinance, which will be published in February

2012. The methodology used to determine the reference tariff is based on

avoided costs approach (generating capacity – 50% CCGT CAPEX + 50% wind

CAPEX - , O&M fixed costs, variable costs, grid costs, CO2).

The reference tariffs are updated quarterly by the Ministerial Ordinance,

taking into account the variation of the FOB price of crude oil (Arabian Light),

the exchange rate of EUR/USD and the Consumer Price Index. The premium

for renewable energy varies with the share of renewable energy sources used

in the installation the previous calendar year. It is also envisaged that the

system of remuneration is subject to subsequent assessment of impacts arising

from the application to be held every two years.

The impacts on the reduction of Cogeração costs are expected to start in 2012

(~25M€) and to gradually evolve until 2020 (~75 M€).

4.2. REVISION OF CMECs ANNUITY

One of the measures that has been discussed with EDP in the context of the

negotiations held with MEE was the revision of the interest rate used for the

calculation of the annuity of the initial amount of CMECs.

The value of the annuity includes, as defined by Decree-Law 240/2004, the

financial costs that are determined at the nominal weighted average cost of

7

capital of the generator. This rate is currently defined in the Ordinance nº

611/2007 from 15th June 2007 at 7,55%.

However, the Decree-Law foresees that the rate used for the calculation of

the financial costs can be reduced in the case CMECs fixed costs are

securitized.

In this context, it has been discussed that this nominal rate should be

adjusted from the current 7,55% to 6,86%, and this will produce savings of

around 4M€/year.

4.3. EXTENSION OF THE F.I.T. (FEED-IN-TARIFF) PERIOD IN WIND FARMS

Given that most of these investments involve project finances or complex

capital and financing structures that were designed in face of the existing

contract FIT’s, an alternative scheme, financially equivalent to the reduction

of the FIT, was discussed in exchange for an extension of the guaranteed

period: instead of lowering as of now the FIT (which might trigger credit

events in the underlying project finance and would thus send these generators

into a default situation), the majority of the generators (around 65% of

installed capacity) have agreed to pay a certain amount upfront in exchange

for buying the extension of this guaranteed FIT.

This operation would entail a payment of 50 M€/year for each additional year

of extension in the guaranteed FIT (proposal was of three year extension,

which meant 150 M€ total over three years). The downside of this measure

would be to extend the current FIT structure for these players for an

additional 3 years, delaying the sale of the wind generated electricity at

market prices.

However, it still needs to be further assessed to ensure financial neutrality

regarding tariff deficit.

4.4. SALE OF CO2 LICENSES

Within the framework of the Directive 2009/29/CE, of April 23rd, amending

Directive 2003/87/EC so as to improve and extend the greenhouse gas

emission allowance trading scheme of the Community to the period 2013-

2020, auctioning should be the basic principle for the allocation of greenhouse

gas emission allowances. This principle is applied to all electric power plants,

8

which will have to buy 100% of the allowances corresponding to their

electricity generation1.

Member States shall determine the use of revenues generated from the

auctioning of allowances. According to the Directive, at least 50% of the

revenues generated from the auction of allowances, or the equivalent in

financial value of these revenues, should be granted to a set of pre-defined

uses, such as the support of the additional costs of renewables, required to

meet the targets committed for 2020.

Since the expected additional costs of renewable electricity generation in

Portugal will be always higher than the expected revenues from CO2

allowances required by the thermal power plants of the electric system (even

in dry hydrological regimes), total allocation of revenues to the tariff is

possible under the framework of the Directive. Assuming a conservative

approach, this measure considers that 80% of the revenues will in fact be

granted to the electric system.

For a CO2 price of 30€2012/ton, the additional revenues to the tariff system

associated with this measure will be ~250 M€/year up to 2017 and ~170

M€/year from 2018 to 2020 (assuming the decommissioning of Sines coal

power plant in 2017).

It should be noted that the sensitivity of the net impact of this measure to the

market price of CO2 allowances is not relevant, since the change of the

revenues is balanced with an equivalent change in the expected electricity

cost.

Additionally, a one-off revenue in 2012 can still be achieved from the sale of

unused CO2 licenses (up to 2012), which can provide a revenue between

20M€-100M€, depending on CO2 sale prices.

4.5. IMPACT OF APPLICATION OF DISCUSSED MEASURES IN THE EVOLUTION

OF THE TARIFF DEFICIT

The following figure show the evolution of the tariff debt assuming an average

real electricity price growth between 1,5 and2,0%/year and taking into

consideration the measures regarding CO2, CHP, wind F.I.T. extension and

0,69pp reduction on the rate of the CMEC annuity.

1 For other sectors covered by the Community scheme, a transitional system should be put in place for which free allocation in

2013 would be 80% of the amount that corresponded to the percentage of the overall Community-wide emissions throughout the period from 2005 to 2007 that those installations emitted as a proportion of the annual Community-wide total quantity of allowances. Thereafter, the free allocation should decrease each year by equal amounts resulting in 30% free allocation in 2020, with a view of reaching no free allocation in 2027

9

Evolution of the tariff deficit (Bn€)1

1 Average annual price growth of 1,85%/year

In this scenario, the adoption of the currently envisaged measures will allow

tariff debt to stabilize by 2014 at 3,6 Bn€ (1,4Bn of existing debt + 2,2Bn of

new debt in the graph above, as the identified measures of CMEC annuity,

Cogeração, Wind Fit and CO2 yield a 0,7Bn reduction in the expected deficit

vis-avis the no-policy change scenario) and reach a value of 0,6Bn€ in 2020.

One important point that must be stated refers to the current deficit (of

2011). This debt has been securitized by EDP having an already pre-defined

profile with a depreciation path of 10 and 15 years and indexed to 3month

Euribor with a 50 and 195 bp spreads respectively2. Given current market

conditions in Portugal and in Europe, it does not seem reasonable or

financially wise in the current context, to accelerate this depreciation profile

in order to fully eliminate it by 2020.

5. ADDITIONAL MEASURES TO BE NEGOTIATED WITH PRODUCERS

There are a set of additional measures that have been considered by the

Government which require a fresh negotiation round with the generation

players. These set of measures should not be in any case unilateral decisions

by the Government, but the result of multilateral negotiations.

This negotiation should be taken with an understanding of the specificity of

each case and also taking into consideration the internal rates of return of

2 The rate is reviews annually taking the 3 month Euribor at the 30

th June each year. The current rate is

thus 1,547% + 0,50%, or 2,047% in total, for the 10 year securitization, and 1,547%+1,95%, or 3,497% in total, for the 15 year securitization.

Evolution of the tariff debt (mM€) - Average real electricity price growth: 1,85%/year 1

5

4

3

2

1

0

CHP Law regulation

2020E

2,3

0,5

2019E

0,7

0,9

0,4

2018E

4,6

0,8

1,5

2017E

4,7

0,9

1,9

2016E

4,8

1,1

2,2

2015E

4,6

1,2

0,1

2014E

4,3

1,4

0,1

2013E

3,8

1,5

0,6

2012E

2,9

1,6

2,2

2011

1,8

2010

1,9

1,9

Existing debt

New debt

CO2

1,9 2,3

0,2

0,3

1,2

1,5

1,8

2,1

0,1

0,20,3

4,3

3,6Rate of the CMEC annuity

1,8

0,9 1,2

Remaining debt0,6

1 Average annual price growth that allows the elimination in 2020 of the new debt

2 Costs associated with the extension of wind FIT (~300 M€) are not considered

Wind FIT extension 2

0,1

0,20,2 0,2

0,2

0,2

0,2

10

each project, which can be found in Annex (calculations provided by MEE) as

well as their comparison to the European benchmark.

We identify below potential measures to be further discussed with the

players, without prejudice of additional/alternative ones being put forth, in

the context of the negotiation process.

5.1 POWER GUARANTEE MECHANISM

The power guarantee mechanism was referred the first time in the Portuguese

legislation in the Decree-Law 264/2007, of July 24th, which has created the

legal provision enabling the existence of a future power guarantee

mechanism.

That mechanism was established by the Ministerial Order 765/2010, of August

20th, and granted to a set of existing or already licensed power plants the

right to receive an incentive to the investment (already done or decided) of

20 000€/MW for the next 7 years.

Understanding that the legal provision for this mechanism only existed

following 2007 Decree-Law, it is fair to assume that decisions made by

generators on whether or not to build capacity was done assuming no such

additional incentive and therefore can be questioned the merit of its

attribution in the referred cases.

One should also note the relevance of power guarantee mechanisms in the

context of the increasingly volatile production capacity environment such as

the one currently in Portugal, where about half of the electricity consumption

depends on renewable sources. Arguably the low predictability of this power

sources increases the need for backup standby fossil power plants, that might

not be operational or available where it not for some sort of power guarantee

mechanism.

On the other hand, these risks can also be mitigated by the increasingly better

interconnection between Portugal and Spain (currently 2000 MW and 3000 MW

in next two years) and by interruptibility mechanism (more than 1000 MW

contracted). Overall, the elimination of this mechanism for the referred

cases, as it now stands, doesn’t seem to put the system in check.

Nonetheless, it is also important to analyze this matter in the context of the

European Union, as for precisely the same reasons, this mechanism is a common

practice in EU, namely in Spain where it is actually higher than in Portugal,

which could give rise to serious competition issues arising in the course of the

MIBEL operation. Nonetheless, energy policy in Spain is currently being reviewed

11

(incentives provided to the electric system have lead to the current tariff deficit

of 26000M€) so any benchmarks should be treated with caution.

It then appears necessary to produce a benchmark study on similar

mechanisms so that, taking in due consideration the current Portuguese

situation, namely the share of volatile generator sources, the type and

characteristics of assets, the legal certainty of the existing mechanism and

the interconnection with Spain, best practices can be identified and a new

and improved power guarantee mechanism can be designed.

Under this context, the revision of the power guarantee mechanism is

intended to (i) eliminate the “incentive to invest” to power plants decided

before the legal framework enabling the existence of the mechanism; and

also (ii) establish a new rational that provides incentive to build additional

generating capacity in the future, taking into account adequate security of

supply levels and the existence of other mechanisms, such as interruptibility

service (in accordance with measure 5.13 of the MoU3).

The redesign of the power guarantee mechanism for the cases of plants that

were licensed prior to 2007 Decree-Law would have an impact of up to

60 M€/year until 2018.

5.2. RENEGOTIATION OF COGERAÇÃO

Besides its regulation, which was discussed above, additional measures should

be explored in a negotiating process with the cogenerators.

There are some areas that can be explored in the negotiation and which have

already been pointed out in the report regarding measure 2R5.7, such as the

possibility of reversing the current framework where cogenerators can sell

100% of their produced energy, whereas before 2002 they could only sell the

excess of their consumption needs.

Also the regulation of renewable cogenerators, which currently don’t have a

limited time horizon for their remuneration, is something that should be explored

in the context of a negotiation process. Simultaneously, there is a need to upgrade

the inspection process to ensure legitimate attribution of the benefits.

3 5.13 v. Take measures by [Q2-2012] to phase out the power guarantee mechanism and reduce the associated policy costs. Incentives for power plants to invest should be revised downwards and phased out in light of the current situation of low electricity consumption, excess production capacity, and the overlapping interruptibility service mechanism, while taking into account developments in the Iberian electricity market and energy security considerations.

12

5.3. RENEGOTIATION OF CAEs

The renegotiation of the CAEs is a very delicate process that should be done

understanding industry constraints.

Back in 2007, when EDP changed its CAEs to CMECs, the rest of the CAEs

didn’t change because of the complicated project finance structure

associated. It is important to realize that, under the current scenario of both

Portuguese and European economy, any breach in these contracts would lead

to a substantial increase in the costs of debt that would ultimately be

reflected in the NES.

Without prejudice of trying to reach some agreement with the generators, it

seems that the risks involved in the renegotiation of the CAEs far surpass its

advantages and potential upside to the sustainability of the NES.

5.4. RENEGOTIATION OF CMECs

The CMECs, which are all owned by EDP, were set in place in 2007 in the

context of the MIBEL.

Overall, the CMECs are covered by contracts that provide some security to

EDP. However, we believe that there is room for negotiation regarding CMECs,

bearing in mind the nature of the contracts and its legal force.

For example, though we recognize the merits of the already mentioned

revision of the interest rate used to calculate the annuity of the initial

amount of CMECs (from 7,55% to 6,86%), we believe that there might still be

room for further improvement by pushing for an additional reduction in the

interest rate and that this should be a negotiation point to explore forcefully.

Independently of proposed paths for negotiation, we believe that there is

potential to further discuss with EDP around necessary measures to ensure

long run sustainability of the NES, which is also in EDP’s interest.

5.5. OTHER RENEWABLES

It is important to further discuss with the players potential alternatives to

improve NES sustainability, but also bearing in mind the need to preserve the

rule of law and the stability of the regulatory environment. Furthermore,

various projects are developed with project finance, and any drastic

reduction in cash flows might trigger credit events that would entail

renegotiations of the project finance with immediate increases in interest

rates.

13

6. CONCLUSION

Assessing the current situation of the NES, we believe the path towards

sustainability can be based on a two pronged approach:

1) Implement the measures which have been put forth previously in

section 4 and that have a nominal impact of around 300M€/year,

resulting in an estimated tariff deficit in 2020 of 0,6 Bn€ in a scenario

of real electricity price growth between 1,5 and 2,0%/year.

2) Set up an independent negotiating team, supported by the MEE, to

negotiate with the generators potential additional measures, including

but not limited to the ones identified and tentatively quantified in this

report, and which would further reduce the tariff deficit and

potentially eliminate it (excluding already securitized deficit) by 2020.

We believe that the ECB/EC/IMF should also have a crucial role in this

process by providing help in gathering information regarding the

international benchmark of returns in the industry, in order to assess

how the different Portuguese projects compare with them.

This negotiation should be developed taking into consideration three

main aspects:

i) Impacts – volume of the impact (euros) of taking a specific measure

ii) Risks – what risks (eg: legal, financial, reputational) are involved in

the measure

iii) Rents – what are the Internal Rates of Return of each project (and

how they compare with industry benchmarks) in order to ensure

that we tackle potential excessive rents

With this mindset, and given the projected scenario for the tariff deficit, we

believe that any additional savings in the context of the negotiation should be

fully reflected in a reduction of the projected average end-consumer price

increases, which are aligned with the spirit of the Commitment for Growth,

Competitiveness and Employment of ensuring the sustainability of energy

prices and placing energy at the service of the economy.

It is important that the negotiation process is quick, given that prolonged

uncertainty in the sector is not beneficial for any of the parties. Therefore,

we recommend that the independent negotiating team is set in the next two

weeks, having as a deadline for closing the negotiations by April 2012.

14

ANNEX: EFFECTIVE RATES OF RETURN

The rates of return, by different kind of generator, are an important input to

analyze potential excessive rents. To that extent, the analysis below done by

the Secretary of State for Energy’s Office tries to identify, by type of

generator, an approximate value of the rates of return that each one has

extracted over the course of the years.

It is important to say that these figures were calculated based on public

available information and therefore cannot reflect fully the details of each

project that depend on a set of variables for which information is not

available.

However, we believe that these figures provide an estimate that should be

used to compare with a benchmark at European Level, to understand the

amount of excessive rents that possibly exist in the Portuguese electricity

market. There doesn’t seem to be a clear definition of excessive rents and to

this end, we would request technical contributions from ECB/EC/IMF in what

regards benchmark of rates of return at international level, and the definition

of excessive rents so that we can better assess the discrepancies of the

existing returns in the Portuguese market.

A. ORDINARY REGIME – PRO4

a. CMECs - Effective rate of return: 14,2%

b. CAEs - Effective rate of return: 12,9%5 and 13,2%6

B. SPECIAL REGIME – PRE7

a. Wind - Effective rate of return: 6,9% (2008) to 9,8% (2003)

b. Photovoltaic - Effective rate of return: 1% (2000) to 10,3% (2009)

c. Biomass - Effective rate of return: 6,0% (2000) to 10,3% (2009)

d. Small Hydro - Effective rate of return: 7,9% (2000) to 11,0% (2010)

e. Cogeração - Effective rate of return: 12,6% (2008) to 16,6% (2003)

Source: Ministry of Economy/Secretary of State for Energy’s Office 4 Nominal, pre-tax 5 Turbogás 6 Tejo Energia 7 Nominal, post-tax

15

Additional information on CAEs

The guidelines for the structural changes in the organization of the electric

system, required to develop a competitive and efficient electricity market, in

accordance with the Directive 2003/54/EC, of June 26th, which established

the common rules for the European internal electricity market, started to be

settled by the Decree-Law 185/2003, of August 20th.

The ability to implement the guidelines for the generating system, defined

with the aim of the creation of the Iberian electricity market (MIBEL), was

provided by the legal authorization created by the Law 52/2004, of October

29th, which has defined the conditions for the early termination of the CAEs

and the correspondent adequate compensation measures.

In the case of the current two remaining CAEs, the Decree-Law 240/2004, of

December 27th, was not applied because their holders have decided for their

non-termination, and the previous remuneration scheme was kept without any

change.

In the case of CAEs power plants, the rate of return was determined

considering the value of assets and the cash-flows given by the “fixed

charged”.

The effective rates of return estimated for the CAEs generating assets are:

Tejo Energia – 13,23% pre-tax nominal 8;

Turbogas – 12,91% pre-tax nominal 9.

Additional information on CMECs

Following the publication of Decree-Law 240/2004, of December 27th, the

agreements for the early termination of the power purchase agreements

(CAEs) of EDP’s binding electricity power plants. The referred Decree-Law

established that in order to maintain the contractual equilibrium of the CAEs,

the owners of such agreements, which include a significant portion of EDP’s

generation capacity in Portugal, have the right to receive a compensation for

the early termination of those agreements (CMECs). The effects of the

termination of these agreements depended on the verification of a set of

conditions, which included the launch of the spot electricity market at the

Iberian level (MIBEL), which came into effect on July 1st, 2007.

8 This effective rate of return does not include the availability premium (1-2 M€/year) and sale of ashes (2-3 M€/year). 9 This effective rate of return does not include the availability premium (4 M€/year average)

16

On February 16th, 2007, the Portuguese Government confirmed the decision to

early terminate the CAEs and implement the CMEC mechanism, closing the

rules to calculate the compensations due to the power generators for such

early termination. On June 15th, 2007, EDP and REN agreed on the early

termination of the CAEs, with effect as of July 1st, 2007. The new CMEC

regulation set the amount of the initial value at 833M€ (corresponding to the

NPV of the CAEs at that date), which can be subject to securitization. It was

also established that EDP would pay 759 M€ for the extension of the use of

hydro public domain, securing the right to operate 26 hydroelectric plants

with a capacity of 4100 MW, under free market conditions for an average

period of over 26 years. Under this context, the effective rate of return of

the generation assets under CMEC regime is determined by the assessment of

those two main financial operations of the CMEC process: the calculation of

the value of the former CAEs when they were terminated; and the calculation

of the value of the extension of the use of water from the end of the hydro

CAEs to the end of the concession of public hydrological domain.

1. CMEC initial value calculation

The initial value of the CMEC was calculated by the difference between the

2007 value of the power plants fixed annual charge, estimated for the

remaining CAEs contracted period, and the expected income stemming from

the foreseen sale of electricity in the wholesale market (at 50€/MWh),

deduced by the estimated annual variable production costs.

According to the Decree-Law 240/2004, of December 27th, the NPV of the

early termination of a CAE for a power plant k (CPk) is given by the following

expression:

The major part of the fixed charges corresponds to the compensation and the

amortization of the power plants net assets. The former CAEs, signed with

17

EDP in 1996, defined a rate of return for the power plant’s net assets of 8,5%

real pre-tax. Since the net asset value is linked to the evolution of a set of

deflators, the equivalent rate of return is 10,67% nominal pre-tax, considering

2% inflation rate used in CMEC framework.

To discount the future cash flows (calculated with 10,67% rate of return), the

Decree-Law 240/2004, of December 27th, established a rate given by the yield

at the date of termination of the CAEs of the Portuguese Government Bond,

with residual maturity closest to the average remaining life of the CAEs,

added by 0,25%. That discount rate was 4,85% nominal, leading to a CMEC

initial value of 833 M€10.

Finally, that NPV was to be recovered along 20 years through an annuity

payment, which will be paid by all consumers. The interest rate used for

calculating the annuity should match the lower of the following rates:

- The weighted average cost of capital (wacc) of the power generation

activity to be defined by the Minister of Economy;

- The annual interest rate associated with payments to the holders of

securities, if CMEC value is securitized

The current rate that is used is based on the wacc of EDP and has been

defined in 2007 by the Minister of Economy as 7,55%.

The calculation of CMEC initial value has, then, three implicit nominal rates:

i) to remunerate the former CAE net assets (10,67%); ii) to calculate the

initial value of the CMEC (4,85%) and; iii) to calculate the annuity

correspondent to that initial value (7,55%).

2. The extension of hydrological regime

After the termination of former CAEs and the beginning of CMEC mechanism,

EDP renegotiated with the Portuguese Government the extension of the use of

water from the end of the hydro CAEs to the end of the concession of public

hydrological resource. These renegotiations were gramed by the Decree-Law

226-A/2007, of May 31st, which also establishes that part of the amount to be

paid by EDP would be used to reduce 2006 and 2007 tariff deficit. It must be

referred that the formers CAEs stated that, one year before the termination

of the hydro power plants CAEs, the TSO has to launch a public tender in

order to concede a new concession for the hydro power plants.

10 The initial value is subject to an annual revision based on the outputs of a model (Valoragua) which simulates Iberian market, taking into account the real data (demand, fuel prices, exogenous contraints, …). The value of the annual revision is given by the difference between the market margin implicit in the initial value (which was estimated) and the correspondent one calculated by Valoragua using the real data.

18

The calculation of the value of the extension of the use of public hydro

resources was done in two steps: i) it was calculated the NPV of the market

residual value of the hydro power plants concessions, which EDP has the right

to receive at the end of the CAEs. To calculate this NPV, it was used a low

discount rate, linked to the longt term Portuguese Government Bonds yields

at that date; ii) the NPV of the expected cash flows of the hydro plants after

CAEs termination had to be determined – the discount rate used to calculate

this NPV was higher, in line with the wacc which was considered adequate for

a European electricity generator.

In conclusion, the full effective rate of return of CMECs adds up to 14.22%11

and it can be illustrated in the figure below:

Additionally, there is a revisibility process which is the annual revision of the

CMEC initial value. It is based on the outputs of a model (Valoragua) which

simulates Iberian market, taking into account the real data (demand, fuel

prices, exogenous constraints …). The value of the annual revision is given by

the difference between the market margin implicit in the initial value (which

was estimated) and the correspondent one calculated by Valoragua using the

real data.

So the CMEC mechanism is composed by both a fixed and an adjustment

parcel:

- Fixed parcel – corresponds to a fixed annual and smoothed income that

represents the forecasted CAE costs for all of each year between 2007

and 2027;

11 This effective rate of return does not include the availability premium (30 M€/year average) and the correction factor applied to hydro and coal generation calculated by Valoragua model in the annual revision of the initial value considering real conditions 10 M€/year average).

0%

2%

4%

6%

8%

10%

12%

14%

16%

Former CAE return Effect of CMEC initialvalue calculation

Effect of hydroconcession extension

Effective return

CMECs effective rate of return

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- Adjustment parcel – corresponds to the amount that corrects, using the

real data, the first parcel that was forecasted; This amount,

corresponding to the annual revisibility, is due until 2017; In 2018,

when the former CAEs have already terminated for half of the plants

(including all thermal) and the remaining maturity of the other will be

less than 10 years, a final adjustment will be determined.

Additional information on PRE

Profitability associated with the investments in the special regime is based in

the internal rate of return (IRR) of the projects. Due to the large number of

PRE power plants (around 500) and the time constraints to develop this work,

the IRR for the different special regime technologies were based on the

relevant characteristics of the projects, with the intent of representing the

technology typical conditions (and not specific projects). If the evolution of

the relevant variables is considered, typical characteristics are adequate to

evaluate the global value of the excessive rents. Nonetheless, any solution to

correct those rents will require a more detailed assessment on the economics

of the different projects.

For the calculation of IRR of the different PRE technologies, the following

variables were carefully determined:

- Feed-in-tariff;

- Licensing and grid connection date;

- Net operating hours;

- Plant expected life-time;

- CapEx (i.e. EPC costs, electrical and grid connection costs, promotion

costs, other);

- OpEx (i.e. O&M, Fuel, Insurances, Rents, other).

These variables were estimated on an annual basis since 2000 until 2010 (for

Cogeração since 1997). For that purpose, several sources were used and

industry experts were consulted to cross-check assumptions and results.

The obtained IRR values, referred to the licensing date, are as follows

(nominal terms):

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Wind 8,3% 9,3% 9,5% 9,8% 9,1% 7,9% 7,8% 7,2% 6,9% 8,1% 7,3%

Photovoltaic 0,9% 1,5% 2,9% 5,0% 5,8% 11,0% 5,0% 5,3% 6,6% 10,3% 9,5%

Biomass 6,0% 6,9% 7,7% 8,5% 9,5% 10,0% 9,8% 9,6% 9,8% 10,3% 10,1%

Small Hydro 7,9% 8,5% 9,0% 9,5% 10,0% 9,9% 10,1% 10,1% 10,5% 10,9% 11,0%

CHP <10MW 15,1% 16,0% 16,5% 16,6% 16,7% 16,0% 15,3% 15,5% 14,7% 15,5% 15,8%

CHP >10MW 15,6% 15,8% 16,4% 16,5% 16,5% 15,5% 14,0% 13,3% 12,6% 12,9% 13,0%