italy’s player on the world green stage; initiate as neutral · upside in ibr, edpr and acciona....

January 19, 2011

INITIATION Enel Green Power (EGPW.MI)

Neutral Equity Research

Italy’s player on the world green stage; initiate as Neutral

Investment view

Enel Green Power (EGP) is among the largest “green utilities”, and on

several measures the most profitable. Exposure to Italian wholesale

power generation gives it high sensitivity to rising power prices, while

ongoing legislative support for renewables, albeit at lower levels, should

allow EGP to benefit from opportunities to grow capacity. However, on

our estimates EGP offers less attractive growth than key renewables

peers (11% EBITDA CAGR 2010-14E vs. 17% for peers) and we see greater

upside in IBR, EDPR and Acciona. We initiate coverage of EGP with a

Neutral rating and €2 12-month target price (24% upside vs. sector 23%).

Core drivers of growth

With 70% of its production exposed to wholesale power prices, the

evolution of Italian (and Spanish) power prices will be a key driver of

EGP. We expect prices to rise in line with higher energy commodities and

believe structural factors will allow Italy to sustain a power price premium

to Europe. Capacity growth is another key driver and we believe EGP can

deliver its target capacity (9.2GW by 2014 from 5.7GW YE09; 10% CAGR).

Risks to the investment case

The evolution of power prices; regulatory developments in Italy (phasing

out of green certificates) and Spain (ongoing energy review); achieving

growth in installed capacity; seasonal production risk (hydro and wind).

Valuation

Our 12-month target price of €2 is based on equally weighted SOTP

(€2.1/share) and EV/EBITDA (€2/share) valuations. EGP trades on 8.4x/7.6x

2011/12E EV/EBITDA vs. 7.2x/6.8x for the utility space (EGP’s 2010-13E

EBITDA CAGR of 11% compares with an average 3.5% for utilities).

Industry context

We expect continued, if less generous support, for renewables in future.

INVESTMENT LIST MEMBERSHIP

Neutral

Coverage View: Cautious

Mariano Alarco +44(20)7774-8817 [email protected] Goldman Sachs International

The Goldman Sachs Group, Inc. does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. For Reg AC certification, see the end of the text. Other important disclosures follow the Reg AC certification, or go to www.gs.com/research/hedge.html. Analysts employed by non-US affiliates are not registered/qualified as research analysts with FINRA in the U.S.

Deborah Wilkens +44(20)7552-2539 [email protected] Goldman Sachs InternationalAndrew Mead +44(20)7774-5735 [email protected] Goldman Sachs International Dario Carradori +44(20)7552-3977 [email protected] Goldman Sachs International

The Goldman Sachs Group, Inc. Global Investment Research

Growth

Returns *

Multiple

Volatility Volatility

Multiple

Returns *

Growth

Investment Profile

Low High

Percentile 20th 40th 60th 80th 100th

* Returns = Return on Capital For a complete description of the

investment profile measures please refer to

the disclosure section of this document.

Enel Green Power (EGPW.MI)

Europe Utilities Peer Group Average

Key data Current

Price (€) 1.61

12 month price target (€) 2.00

Upside/(downside) (%) 24

Market cap (€ mn) 8,040.0

Enterprise value (€ mn) 11,803.0

12/09 12/10E 12/11E 12/12E

Revenue (€ mn) 1,895.0 2,342.0 2,489.5 2,694.1

EBIT (€ mn) 791.0 806.1 861.2 950.5

EPS (€) 0.13 0.09 0.09 0.10

EV/EBITDA (X) NM 9.0 8.4 7.6

P/E (X) NM 17.4 18.1 16.5

Dividend yield (%) NM 1.4 1.7 1.8

FCF yield (%) NM (5.6) (1.8) (0.2)

CROCI (%) NM 7.2 6.8 7.0

CROCI/WACC (X) -- -- -- --

EV/GCI (X) NM 0.8 0.7 0.7

Price performance chart

1.50

1.52

1.54

1.56

1.58

1.60

1.62

1.64

1.66

1.68

1.70

Oct-10 Nov-10 Dec-10

330

335

340

345

350

355

360

365

370

375

380

Enel Green Power (L) FTSE World Europe (EUR) (R)

Share price performance (%) 3 month 6 month 12 monthAbsolute -- -- --

Rel. to FTSE World Europe (EUR) -- -- --

Source: Company data, Goldman Sachs Research estimates, FactSet. Price as of 1/18/2011 close.

January 19, 2011 Enel Green Power (EGPW.MI)

Enel Green Power: Summary Financials

Analyst Contributors

Mariano Alarco

[email protected]

Deborah Wilkens

[email protected]

Andrew Mead

[email protected]

Dario Carradori

[email protected]

Fred Barasi

[email protected]

Goldman Sachs Global Investment Research 2

Profit model (€ mn) 12/09 12/10E 12/11E 12/12E Balance sheet (€ mn) 12/09 12/10E 12/11E 12/12E

Total revenue 1,895.0 2,342.0 2,489.5 2,694.1 Cash & equivalents 144.0 144.0 144.0 144.0

Operating costs (688.0) (1,025.2) (1,065.5) (1,132.7) Accounts receivable 512.0 655.8 684.6 754.3

R&D 0.0 0.0 0.0 0.0 Inventory 31.0 38.3 40.7 44.1

Lease payments 0.0 0.0 0.0 0.0 Other current assets 365.0 365.0 365.0 365.0

Other operating profit/(expense) 0.0 0.0 0.0 0.0 Total current assets 1,052.0 1,203.1 1,234.4 1,307.4

EBITDA 1,207.0 1,316.8 1,424.1 1,561.4 Net PP&E 7,200.0 9,039.6 9,536.5 9,889.7

Depreciation & amortisation (416.0) (510.7) (562.9) (610.9) Net intangibles 791.0 1,716.0 1,716.0 1,716.0

EBIT 791.0 806.1 861.2 950.5 Total investments 296.0 621.0 690.4 768.1

Net interest income/(expense) (133.0) (107.7) (126.0) (157.1) Other long-term assets 155.0 305.0 305.0 305.0

Associates 0.0 5.0 19.4 27.7 Total assets 9,494.0 12,884.6 13,482.2 13,986.2

Profit/(loss) on disposals 0.0 0.0 0.0 0.0

Others (recurring) 0.0 0.0 0.0 0.0 Accounts payable 454.0 562.1 597.5 646.6

Pretax profits 658.0 703.5 754.6 821.1 Short-term debt 4,528.0 2,028.0 2,028.0 2,028.0

Income tax (219.0) (211.0) (256.6) (283.3) Other current liabilities 436.0 436.0 436.0 436.0

Tax rate (%) 33.3 30.0 34.0 34.5 Total current liabilities 5,418.0 3,026.1 3,061.5 3,110.6

Minorities (21.0) (29.8) (52.9) (49.8) Long-term debt 1,131.0 1,606.1 1,799.4 1,870.0

Preferred dividends 0.0 0.0 0.0 0.0 Other long-term liabilities 381.0 724.0 724.0 724.0

Net income (pre-exceptionals) 418.0 462.7 445.2 488.0 Total long-term liabilities 1,512.0 2,330.1 2,523.4 2,594.0

Other non-recurring items post tax 0.0 0.0 0.0 0.0 Total liabilities 6,930.0 5,356.2 5,584.9 5,704.6

Net income 418.0 462.7 445.2 488.0

EPS (underlying) (€) 0.13 0.09 0.09 0.10 Preferred shares 0.0 0.0 0.0 0.0

EPS (basic, reported) (€) 0.13 0.09 0.09 0.10 Total common equity 2,384.0 6,818.7 7,148.2 7,502.7

Weighted shares outstanding (mn) 3,160.0 5,000.0 5,000.0 5,000.0 Minority interest 180.0 709.8 749.2 779.0

Common dividends declared 0.0 115.7 133.6 146.4 Total liabilities & equity 9,494.0 12,884.6 13,482.2 13,986.2

DPS (€) 0.00 0.02 0.03 0.03 Capitalised leases 0.0 0.0 0.0 0.0

Dividend payout ratio (%) 0.0 25.0 30.0 30.0 Capital employed 8,223.0 11,162.6 11,724.8 12,179.7

Dividend cover (X) NM 4.0 3.3 3.3

Growth & margins (%) 12/09 12/10E 12/11E 12/12E Adj for unfunded pensions & GW 0.0 0.0 0.0 0.0

Revenue growth -- 23.6 6.3 8.2 Adj capital employed 8,223.0 11,162.6 11,724.8 12,179.7

EBITDA growth -- 9.1 8.1 9.6 Gross cash invested 11,665.0 15,937.6 17,062.7 18,128.5

EBIT growth -- 1.9 6.8 10.4

Net income growth -- 10.7 (3.8) 9.6 Ratios 12/09 12/10E 12/11E 12/12E

EPS growth -- (30.0) (3.8) 9.6 CROCI (%) NM 7.2 6.8 7.0

DPS growth -- -- 15.5 9.6 CROCI/WACC (X) -- -- -- --

EBITDA margin 63.7 56.2 57.2 58.0 ROIC (%) -- 7.1 6.3 6.5

EBIT margin 41.7 34.4 34.6 35.3 ROIC/WACC (X) -- -- -- --

ROA (%) NM 4.1 3.4 3.6

Cash flow statement (€ mn) 12/09 12/10E 12/11E 12/12E WACC (%) -- -- -- --

Net income 418.0 462.7 445.2 488.0 Inventory days 6.0 6.0 6.0 6.0

D&A add-back (incl. ESO) 416.0 510.7 562.9 610.9 Asset turnover (X) 0.3 0.3 0.3 0.3

Minority interest add-back 21.0 29.8 52.9 49.8 Net debt/equity (%) 215.1 46.4 46.6 45.3

Net (inc)/dec working capital (62.0) (43.0) 4.1 (24.0) EBITDA interest cover (X) 9.1 12.2 11.3 9.9

Other operating cash flow 104.0 (85.0) (19.4) (27.7)

Cash flow from operations 897.0 875.1 1,045.7 1,097.0 Valuation 12/09 12/10E 12/11E 12/12E

EV/sales (X) NM 5.0 4.8 4.4

Capital expenditures (793.6) (1,250.2) (1,109.8) (1,014.1) EV/EBITDAR (X) NM 9.0 8.4 7.6

Acquisitions 0.0 (1,300.0) 0.0 0.0 EV/EBITDA (X) NM 9.0 8.4 7.6

Divestitures 0.0 0.0 0.0 0.0 EV/EBIT (X) NM 14.6 13.8 12.5

Others 0.0 0.0 0.0 0.0 P/E (X) NM 17.4 18.1 16.5

Cash flow from investing (793.6) (2,550.2) (1,109.8) (1,014.1) Dividend yield (%) NM 1.4 1.7 1.8

FCF yield (%) NM (5.6) (1.8) (0.2)

Dividends paid (common & pref) 0.0 0.0 (129.1) (153.5) EV/GCI (X) NM 0.8 0.7 0.7

Inc/(dec) in debt 76.0 (2,024.9) 193.3 70.6 EV/adj. capital employed (X) NM 1.1 1.1 1.0

Other financing cash flows 0.0 3,700.0 0.0 0.0 Price/book (X) NM 1.1 1.0 1.0

Cash flow from financing 76.0 1,675.1 64.1 (82.9)

Total cash flow 0.4 0.0 0.0 0.0 Note: Ratios are adjusted for leases where appropriate. Only separately disclosed where significant and ongoing.

Capex/D&A (%) 190.8 244.8 197.2 166.0

Reinvestment rate (%) 82.8 136.2 106.6 90.5

Cash flow cover of dividends (X) NM 7.9 7.8 7.7 Note: Last actual year may include reported and estimated data.

Free cash flow cover of dividends (X) NM (3.9) (1.1) (0.1) Source: Company data, Goldman Sachs Research estimates.



Contents

Second renewable player worldwide, with power price exposure 4

Peer comparison: smaller than IBR, yet with higher returns 10

Valuation: €2/share using multiples & SOTP, in line with sector 18

Italian power prices remain linked to Brent 26

Focus on renewable capacity growth in selected regions 32

Italy and Iberia are key for growth, Europe and Americas follow 36

Risks: regulation, growth, prices and future level of feed in tariffs 45

Financials: double-digit growth rates 49

Company and management profile 55

Appendix 1: Italian generation market and EU power demand 57

Large capacity additions since 2002, some in construction 58

Appendix 2: Enel Green Power pipeline 60

Prices in this report are as of the close of January 14, 2011 unless otherwise stated.



Second renewable player worldwide, with power price exposure

With almost 70% of its generation exposed to power prices, Enel Green Power’s

earnings are among the most sensitive to a rise (or fall) in power prices in the

utilities sector. Reflecting the Italian power price premium (vs. the European

average) EGP enjoys higher EBITDA per MW and MWh than its closest peers. With

its strong balance sheet and a large, geographically and technologically diversified

pipeline, we believe that the company can sustain an average 11% EBITDA growth

rate through 2010-2014E. This is below the average rate we expect from its

renewables peers (17%). We initiate coverage of Enel Green Power with a Neutral

rating, and a 12-month €2 target price implying 25% potential upside (vs. a 23%

median potential upside for the sector).

Italian core, with world presence and diversified technologies

Having total production from renewable sources of 22TWh in 2010E, EGP ranks as the

second largest renewables “green utility” in the world after Iberdrola Renovables (IBR;

27TWh of production in 2010E). More than half of Enel Green Power’s assets are in Italy,

representing 55% of 2010E production. Iberia represents 15% of its 2010E production, and

Latin and North America 16% and 12% respectively. On a global basis, we expect 49% of

its 2010E production to come from hydro, 25% from geothermal, 23% from wind and 3%

from other (biomass, cogeneration and solar).

Diversified asset base: higher profitability yet low incentives

As a result of its strong presence in the attractive Italian renewables market, and the high

load factor of its technologies, Enel Green Power is able to achieve higher EBITDA per

MW and MWh than most of its renewable peers: we forecast in total €1.3 bn of EBITDA in

2010 from renewables (compared to €1.4 bn for IBR) despite the fact that, compared to its

closest and purest peers, IBR, EDP Renovaveis (EDPR) and EDF Energies Nouvelles (EDF

EN), it has the lowest percentage of incentivized production (36% in 2010E compared to

other green utilities at around 50%). In total, incentives (green certificates in Italy,

premium in Spain and tax breaks in the US) represented 32% of the EGP’s 2009 EBITDA.

Benefit from rising power prices; Italian power premium to stay

The main driver of Enel Green Power’s high profitability is its exposure to the Italian

power market. With almost 70% of its production is exposed to wholesale power price

changes, Enel Green Power should benefit from rising wholesale prices. We estimate that

each €10/MWh change (unhedged) in the wholesale power price would have an 11%

impact on EBITDA and a 22% impact on net income (2012E). We expect Italian power

prices to rise from 2012 on the back of rising European gas prices. Italian wholesale

power prices, currently trading at around a €20/MWh premium to northern European

prices, are unlikely to fall to German levels in our view (specific mix of the Italian

generation market, temporary green certificates costs, and high peaks and grid

bottlenecks), and we believe Italy should be able to sustain a €9-23/MWh premium to

Europe through to 2015, and a €2-12/MWh premium thereafter.

Large pipeline, strong balance sheet allows for profitable growth

Enel Green Power expects to add 3.5GW of capacity by 2014, through €5.2 bn of capex,

increasing its installed base from 5.7GW currently to 9.2GW (+60% growth). We expect

less production growth (43%), as the planned investments in wind and solar have lower

load factors than existing geothermal and hydro. We expect two-thirds of capex to be

directed at wind. EGP should be able to fund its growth from internal cash flows and its

balance sheet (2.4x 2010E net debt/EBITDA, expected to fall to 1.9x by 2014E) and could



potentially double its growth rates if it decided to gear up to the level of other green

utilities. Compared to its closest peers, Iberdrola Renovables (IBR), EDP Renovaveis

(EDPR) and EDF EN, we expect Enel Green Power to report lower growth, with a 2010-

2014E EBITDA CAGR of 11.1% compared to the group average of 17%. In terms of net

income, we expect a 9.3% CAGR, compared to the green utilities’ average 22%.

Key risks: regulation, falling support for renewables, power prices

Our forecasts incorporate regulatory changes in Italy and Spain

As part of Enel Green Power’s production receives incentives, adverse regulatory changes

could affect its profitability. Italy has recently announced a change to its remuneration for

renewables, aiming to phase out the existing green certificates from 2013 for new projects,

and from 2016 for exiting assets. The green certificate system will be replaced by fixed

feed-in tariffs for different technologies, with the level of the tariffs as of yet undecided.

We expect green certificates to be supported by the government until 2015, and

conservatively assume that wind farms receive feed-in tariffs above pool prices from 2013

(at €110/MWh; wind currently receives c.€160/MWh), with no further support for new

hydro or geothermal. In Spain, we assume wind revenues is capped (at €77.5/MWh) from

2012.

We expect ongoing support for renewables, particularly in Europe, to continue

Overall, as Europe has already set its 2020 renewables targets through a binding directive

for member states, we expect support for renewables to continue, though this support is

likely to be less generous over time as technology improves and capital costs decline. A

faster than anticipated reduction of subsidies could pose a risk to EGP’s profitability.

Delivery of capacity growth targets is a further risk

EGP is aiming to increase installed capacity to 9.2GW (YE2014) from 5.7GW (YE2009, or

700MW pa). A failure to reach this target is a risk to our estimates. However, over the last

decade, Enel has added c.100MW of renewables pa in Italy and in the last two years, Enel

has also added 300MW pa internationally. Additionally, Endesa has made just over

300MW of annual additions since 2005 (all of Endesa’s renewable activities in Iberia have

been within Enel Green Power España since 2Q2010). As a result, we believe that 700MW

pa is an achievable target for the company going forward.

High exposure to power prices poses a risk in the event that prices fall

As a result of the relatively low weight of incentives or fixed-price tariffs (PPA or “feed-in

tariffs”), Enel Green Power is significantly exposed to wholesale power prices. Power

prices are in turn determined by the evolution of gas, coal and CO2 prices, as well as

supply and demand balances in respective markets. A fall in the prices of these

commodities could lead to a fall in Italian or Spanish wholesale power prices.

We value EGP at €2 per share, based on multiples and SOTP

Renewable peers to be key comparables

As a result of its size, profitability and diversified geographical presence, we believe that

IBR is the most direct comparable, followed by EDPR. To a lesser extent, EDF Energies

Nouvelles and Acciona are also good comparables. These green utilities currently trade

between 9.2x and 11.6x 2011E EV/EBITDA (average 10x) and between 7.9x and 10.3x

2012E EV/EBITDA (average 9.4x), with EGP trading at 8.2x and 7.5x in 2011E and 2012E.

We believe this discount reflects potentially slower EBITDA growth (EGP 11% vs. 17% for

peers) and uncertainty regarding the level of remuneration for renewables in Italy from

2013.



Exhibit 1: We see 25% potential upside for EGP vs. 23% for the utility sector as a whole – EGP trades at a slight

discount to peers due to slower growth and uncertainty regarding renewable remuneration in Italy, in our view Selected valuation metrics for Enel Green Power and other renewable utilities

All share prices in euro EV/EBITDA multiples calculated using period average net debt. Consequently, multiples are slightly lower than those shown on the front page.

Source: Goldman Sachs Research estimates. For important disclosures, please go to http://www.gs.com/research/hedge.html.

SOTP and multiples imply €2/share valuation; upside in line with sector

As for our broader utilities coverage, we combine short-term and longer-term valuations

in our Enel Green Power price target. Our short-term valuation is based on an EV/EBITDA

multiple, adjusted for forward-looking growth (this is how we value the renewable peers).

EGP’s multiple-based valuation is €2/share. Our long-term valuation of EGP is based on a

SOTP analysis (€2.1/share). The average of these valuations implies 25% potential upside,

vs. a utilities sector median of 23%.

Exhibit 2: Our SOTP analysis suggests a €2.1/share valuation: Hydro, wind and

geothermal are key assets Enel Green Power SOTP analysis

Source: Goldman Sachs Research estimates.

Current Potential EV/EBITDA 2011E 2012E P/E CROCI

Valuation Comparison Rating share price upside 2010E 2011E 2012E 2013E at target price 2010E 2011E 2012E 2013E 2010E 2011E 2012E 2013E

Acciona Buy 55.5 37% 10.0x 9.2x 7.9x 6.9x 10.3x 8.8x 22.3x 20.2x 12.8x 9.9x 5.8% 6.1% 6.8% 7.5%

EDF Energies Nouvelles Neutral 31.8 10% 13.3x 11.6x 10.3x 9.5x 11.9x 10.6x 21.8x 19.3x 15.8x 15.0x 7.1% 7.3% 7.7% 7.9%

EDP Renovaveis Buy 4.4 32% 11.2x 9.7x 8.5x 7.9x 11.0x 9.7x 48.4x 36.4x 22.9x 20.7x 5.0% 5.8% 6.6% 6.9%

Iberdrola Renovables Buy 2.6 29% 10.1x 9.3x 8.1x 7.1x 11.1x 9.6x 25.5x 21.9x 17.5x 14.5x 6.8% 6.7% 7.0% 7.2%

Enel Green Power Neutral 1.6 25% 9.5x 8.2x 7.5x 6.8x 9.4x 8.7x 17.3x 18.0x 16.4x 14.1x 6.8% 6.8% 7.0% 7.2%

Enel Green Power SOTP€ mnYE2011 € mn €/share € mn/MW CommentsHydro 5,173 1.0 2.0 In Italy, valuation until end of concessions in 2034, Italy 3,022 assuming all incentives end in 2015 and power price of €79 LatAm 1,614 thereafter. For LatAm, valuation until 2043. No residual Other 538 value for either assetGeothermal 2,763 0.6 3.6 In Italy valuation until end of concessions in 2024, Italy 2,657 assuming all incentives end in 2015 and power price of €79 Other 106 thereafter. Residual value of 33% of capexWind 3,901 0.8 1.3 Assumes 5 yr average age of wind farms. In Italy, assume Italy 724 green certificates until 2015, then fixed tariff of €110/MWhSpain 1,781 1.1 In Spain, assumes power price is capped at €77.5/MWhEurope 637 post 2012Other 759Solar 411 0.1 4.2 High value of solar farms in Italy, assumes €440 solar Italy 319 power remuneration (fixed tariff + pool), and capexOther 92 costs of €2.8/WpOther 226 2.0 Biomass & cogeneration assetsTotal EV Operating assets YE 2011 12,474 2.5

Pipeline & WIP (2012-2015E) 1,010 0.2 Includes NPV of pipeline & work in progress

Solar retail 294 0.1 Using 7x 2011E EV/EBITDA, in line with European SolarTotal Enterprise Value 13,777 2.8 Implied valuation of 9.7x 2011E EV/EBITDANet Debt, including tax liability (3,455) (0.7) Year end 2011 Net DebtMinorities & provisions (918) (0.2) Mostly Enel Green Power España & Fortuna hydro plantAssociates 913 0.2 Mostly wind, solar& waste; valued at 1.4x YE2011E bookRemaining Equity value 10,317Number of shares 5,000Value per share 2.1



World’s second largest green utility and most profitable

ENEL Green Power is the second largest “green utility” in the world (on our

estimate of 2010 production). Furthermore, it is the most diversified in terms of

geography and technology of operations. This diversification is, in our view, likely to

be further enhanced through the development of the planned pipeline which should

see significant growth, particularly in wind assets outside Italy. As shown in the

following section, as a result of high load factors at its hydro and geothermal plants,

and its exposure to the attractive Italian market, its EBITDA/MW is the highest

among green utilities.

Exhibit 3: EGP has a wide geographical presence and is run as three divisions: Italy & Europe, Iberia and Latin America

and North America 2009 pro-forma data

Source: Company data, Goldman Sachs Research estimates.

Acquisition of Endesa’s renewables in 1H10 has increased presence in Iberia

The inclusion of Endesa's renewable assets since March 2010 (60% owned) has increased

the group’s exposure to the Iberian market: using pro-forma data (assuming the inclusion

of Endesa’s renewable assets from January 1, 2009) rather than actual (from March 2010)

Italy’s share of sales would fall from 62% to 56%. Iberia’s share would increase from 5%

to 15%.

Enel Green Power’s production in 2009 was 18.9TWh, or 20.9TWh using pro-forma data.

In 1H 2010, Enel Green Power’s production was 10.8TWh, all from renewable sources, of

which 59% was from Italy and 11% from Iberia (the Iberian assets only started

contributing from April 2010). Likewise, the acquisition of Endesa’s renewables activity

has increased the weight of wind from 15% in 2009 to 21% (2009 pro-forma). In 1H 2010

wind production was 20% of the total.

Enel Green Power

Operating 5,761 MWProduction 20.9 TWh

In execution 1.2 GW

Pipeline 29.9 GW

Italy and Europe


In execution 0.4 GW

Pipeline 5.8 GW

Iberia and Latin America


In execution 0.5 GW

Pipeline 15.6 GW

North America

Operating 788 MW

Production 2.4 TWh

In execution 0.3 GW

Pipeline 8.3 GW

EGP presence



Exhibit 4: Italy represents just over half of revenues…

Revenue by division, 2009PF, €2,109 mn

Exhibit 5: ... but generates two-thirds of EBITDA

EBITDA by division, 2009PF, €1,331 mn

Source: Company data.


Exhibit 6: Production diversified by geography, with Italy

dominant… Electricity production by geography (2009PF, TWh); total

pro-forma production 20.9TWh

Exhibit 7: …and by technology

Electricity production by technology (TWh, 2009PF)



Economic stake in c.340MW of associates

Enel Green Power has several stakes in associates (30%-48%), with a gross capacity of

970MW at the end of 2009, particularly in wind in Portugal and Spain and geothermal in El

Salvador. In Portugal, Enel Green Power participates with a 30% stake in ENEOP (in which

EDPR also participates with 40%), which is developing 1,200MW of wind capacity

following the award of the 2005-2006 concession tender. ENEOP will be split in 2013,

upon completion of the projects, and Enel will start fully consolidating c.360MW. In El

Salvador, Enel owns 36.2% of La Geo SA de CV, which owns 204MW of geothermal plants

and has a net cash position. In Spain it has stakes in several wind farms and one waste

company.

Italy

56%

R of Eur

2%

Iberia

15%

Latam

12%

N.

America

7%

Retail

8%

Italy

65%R of Eur

2%

Iberia

16%

Latam

9%

N.

America

7%

Retail

1%

North America

12%

Iberia14%

Latam17%

Italy56%

R of Eur1%

Hydro51%

Geothermal

25%

Wind21%

Other3%



High load factors at Enel Green Power’s renewable plants set it apart

Production is more diversified than capacity as a result of the high load factor of

geothermal generation (load factors exceed 80%), with a median load factor of 88% since

2002. Italian hydro plants also have quite high load factors (c.46%), as the hydro plants

are run of river plants. Load factor at the Latin American hydro plants is even higher at

60% on average (with an almost 70% load factor in its largest hydro plant, the 300MW

Fortuna plant, in Panama). The average load factor of 41% for 2010E makes Enel Green

Power stand out versus other European green utilities, as explained in the following

section.

Exhibit 8: Italy dominates capacity… Installed base by geography, (MW, 2009PF); total installed

base was 5,667MW

Exhibit 9: …as does hydro by technology

Installed base by technology, (MW, 1H2010)



Retail activities high in revenues, small in EBITDA

Enel Green Power also operates renewable equipment retail activity through Enel.Si,

which operates as a franchise. The group’s retail activities are predominantly in Italy and

involve selling solar panels and other renewable products (e.g. mini-wind) to domestic

and business customers. While these activities generated €178 mn of revenue in 2009, or

9.4% of the group total, they provided only €7 mn (0.6%) of the group’s EBITDA.

Furthermore, EGP has started a joint venture (with Sharp and STM with 33% each) to

manufacture thin film modules in Italy through a 160MW solar fabrication plant. This is

due to start operating by end-2011. In a separate 50/50 joint venture with Sharp, EGP aims

to develop solar farms in the EMEA region (where the company expects 500MW of

projects to be developed by 2016). EGP has recently invested c.€200 mn in these JVs (post

1H2010).

North America

14%

Iberia18%

Latam18%

Italy46%

Rest of Europe

4%

Hydro44%

Geothermal

13%

Wind41%

Other2%



Peer comparison: smaller than IBR, yet with higher returns

We expect Enel Green Power to report lower growth than its peers. However, it has

a more diversified asset base and pipeline and a stronger balance sheet.

Iberdrola Renovables and EDP Renovaveis best comparables

As a result of its size, profitability and diversified geographical presence, Enel Green

Power is most comparable to “green utilities” such as Iberdrola Renovables and EDP

Renovaveis. EDF Energies Nouvelles and, to a lesser extent Acciona, are also good

comparables. In the case of Acciona, it is worth noting that it has a higher weight of

non-energy assets in its mix (currently around 30% of its EBITDA), and that it has a

different shareholder structure (all the other peers have a utility as a parent company,

which can allow for easier access to financing).

Broad comparison also possible with global players

On a global basis, as a result of the large weight of hydro within Enel Green Power, the

company could be also broadly compared to other hydro players such as Rushydro (6.8x

2011E EBITDA) or Brazilian hydro generators such as CESP, AES Tiete or Tractebel, which

currently trade between 8.2x and 6.9x 2011E EBITDA. However, as the bulk of these

company’s exposures are to different markets and different regulation (particularly in

Russia), we believe that such comparison should be only on a broad basis.

Renewables often compared on capacity, but EGP has higher load

factors

Exhibit 10: Relatively low installed capacity... Installed capacity, MW 2010E

Exhibit 11: ...but with the highest load factors Load factor, % 2010E



0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

EGP IBR EDPR EEN Acciona

Installed capacity, end 2010E

10%

15%

20%

25%

30%

35%

40%

45%


Load

factor, 2010E



We believe Enel Green Power is best compared on production

(reflecting its high load factors) or EBITDA (higher profitability)

Exhibit 12: Enel Green Power has the second highest

production among green utilities 2010E

Exhibit 13: ...and its EBITDA from renewables is close to

Iberdrola Renovables’ EBITDA (excludes EBITDA from non-renewable activities or

traditional thermal generation); 2010E



Technological mix is more diversified, its exposure more to Italy,

peers are more exposed to Iberia and the US...

Exhibit 14: More hydro and geothermal for EGP

Output by technology, 2010E, rebased to 100

Exhibit 15: Less US exposure for EGP 2010E EBITDA by region, rebased to 100. *For Acciona,

which has no UK, the UK color represents Australia



...and a lower percentage of its production is reliant on subsidies

As a result of its greater hydro and geothermal production in Italy, both EGP’s percentage

of production and its percentage of EBITDA derived from incentives is lower than green

utility peers. Although the current review of green certificates in Italy (to be phased out

over 2013-2015) highlights some regulatory uncertainty.

0

5,000

10,000

15,000

20,000

25,000

30,000


Production in

2010E, GWh

0

200

400

600

800

1000

1200

1400

1600


EUR m

n

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

EGP IBR EDPR Acciona EEN

Other

Solar

Wind

Geothermal

Hydro

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

EGP IBR EDPR Acciona EEN

Non‐renewable

Latam

North America

UK*

Rest of Europe

Iberia

Italy



Exhibit 16: EGP has both the lowest percentage of

production which is incentivized ... Percentage of production which is incentivized

Exhibit 17: ... and also the lowest portion of EBITDA

explained by incentives Percentage of EBITDA explained by subsidies (for Acciona

percentage of energy EBITDA only, for IBR we exclude non-

renewable EBITDA)

Source: EGP data for EGP 2009, Goldman Sachs Research estimates for rest.


Lower growth, reflecting more conservative targets in our view

Exhibit 18: Growth rates are lower than at peers... Capacity growth, MW

Exhibit 19: …also in production terms

Production growth, GWh



...while profitability per MW is highest at EGP

As a result of high load factors, a large exposure to Italy (where returns for renewables

are higher), and lower exposure to the US (where returns tend to be lower), Enel Green

Power has the highest EBITDA profitability per MW among its peers. On a per GWh basis

(1,000MWh =1GWh), Enel Green Power’s profitability comes second behind EDF EN,

which has a large weight of solar.

32%

98% 100% 100%93%

51%

92% 91% 94% 91%

0%

20%

40%

60%

80%

100%

120%

EGP IBR EDPR EDF EN Acciona

2009E

2014E

36%

52%49%

55%

62%

0%

10%

20%

30%

40%

50%

60%

70%


2010E

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2010E 2011E 2012E 2013E 2014E

Annual capacity additions, M

W

EGP

IBR

EDPR

EEN

Acciona

0

1,000

2,000

3,000

4,000

5,000

6,000

2010E 2011E 2012E 2013E 2014E

Annual production growth, G

Wh

EGP

IBR

EDPR

EEN

Acciona



Exhibit 20: Enel Green Power should maintain the

highest profitability (EBITDA) per MW For Acciona we only include renewable business EBITDA, for

others we include total group EBITDA/renewable production

Exhibit 21: ... and EBITDA per GWh produced Total EBITDA for the group per GWh of renewable

production (for Acciona we only include the renewable

business); € mn



Scope to exceed business plan targets thanks to pipeline and

balance sheet

Enel Green Power’s pipeline (netted to reflect the company’s view of the probability of

success) is 1.8x its planned capacity increase as per its business plan to 2014. As 1.6GW

of capacity is already under construction or in execution (as of 9M2010), there is scope for

capacity growth to exceed forecasts in our view.

Furthermore there is a significant amount of planned investment beyond 2014. As a result

of the availability of its pipeline and its technological diversification, we believe that the

company could deliver its targeted unleveraged IRR of 9%-12%. However, we highlight

that the introduction of feed-in tariffs for renewables in Italy (moving away from the

current system of green certificates) creates uncertainty as the level of feed-in tariffs for

new renewable plants from 2013 will be set by auctions, with a minimum, as of yet

undetermined level of returns. In our estimates we assume new hydro and geothermal

plants get tariffs no higher than pool prices from 2013 (implying IRRs of 9%-11%) as these

two technologies are more mature and lower cost. We assume that Italian wind farms get

€110/MWh, consistent with IRRs for 7.5%, equal to returns we factor in Spain. EGPs strong

balance sheet, in our view, provides scope to deliver additional growth if incentives for

new renewables remain attractive.

30GW of pipeline – distributed across the continent with an overweight in wind

The pipeline for planned development to 2014 is greatest for Iberia (Spain and Portugal),

followed by North America and Latin America. While wind represents the largest part of

the pipeline, we would also expect it to see the lowest conversion rates.

More than one-third of the expected growth already in execution

In this growth context, EGP expects to increase its generation capacity by 3.5GW to

9.2GW (from 5.7GW pro-forma at end 2009). Of this total, 1.6GW is in execution, covering

46% of the total expected installation over the 2010-2014 period.

0.050

0.070

0.090

0.110

0.130

0.150

0.170

0.190

0.210

0.230

0.250

2010E 2011E 2012E 2013E

EUR m

n EBITDA/M

W

EGP IBR (renewables) EDPR EEN Acciona (renewables)

0.040

0.045

0.050

0.055

0.060

0.065

0.070

0.075

0.080

0.085

0.090

2010E 2011E 2012E 2013E

EUR m

n EBITDA/G

Wh

EGP IBR (renewables) EDPR EEN Acciona (renewables)



Exhibit 22: We expect EGP to reach its 9.2GW of capacity target in 2014, as one-third of

the total is already in execution and the pipeline is significant… Expected MW additions (in MW)

Source: EGP data (2009PF, in execution, EGP target 2014), Goldman Sachs Research estimates (other development, GS 2014).

Our estimate for capacity growth is broadly in line with company targets, with

comparable capex spend (€5.2 bn + €300 mn in associates)

Exhibit 23: ... by spending c.€5.3 bn in capex (€300 mn in associates) largely in line with

EGP’s guidance Expected capex 2009-2014 (€ mn); €300 mn represents financial investments in associates

Source: EGP data (Total EGP estimate of €5.2 bn and €0.3bn), Goldman Sachs research estimates (Hydro, Geothermal, Wind, Solar, Total).

We believe that EGP is highly likely to deliver its stated plan for two key reasons. First, its

targeted 3.5GW of incremental capacity (2009PF-2014) is backed up by 1.6GW of projects

already in execution (202MW expected commercial operation date 4Q2010, 548MW under

construction and 811MW ready to build as of 9M2010, includes ENEOP). Secondly, EGP’s

pipeline of projects is significant relative to its expected capacity build out.

5,667

9,173 9,200

1,273

2,233

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2009PF in execution other development GS 2014 EGP target 2014

MW

469

5,298 5200

663

300 300

3,740

420

0

1,000

2,000

3,000

4,000

5,000

6,000

Hydro Geothermal Wind Solar Total Total EGP estimate

Eu

ro m

n

+ 5mn of others

Financial investments



Track record supportive of 700MW of annual additions

While part of Enel Green Power’s pipeline has been built through acquisitions in recent

years, we believe the company has a good track record developing assets, taking into

account Endesa’s expertise. Over the last decade, Enel has been adding c.100MW of

renewables pa in Italy, split among hydro, geothermal and wind. In the last two years,

Enel has also added some 300MW pa internationally, while additionally, Endesa has made

just over 300MW of annual additions since 2005 (all of Endesa’s renewable activities in

Iberia have been within Enel Green Power España since 2Q2010). As a result, we believe

that 700MW pa is an achievable target for the company going forward.

Exhibit 24: EGP’s pipeline is supportive of our capacity addition estimates GS forecasts of net capacity additions (2010-2014) vs. EGP’s risk-weighted execution pipeline

and gross execution pipeline (2010-2014E)

EG

EGPs risk weighted pipeline is its gross pipeline weighted by probability of success. As defined by EGP: Highly

confident (90% success) on 5% of pipeline, Likely (50% success) on 19% of pipeline, Potential (20% success) on 76%

of pipeline

Source: Goldman Sachs Research estimates for GS forecast net capacity additions, EGP data for EGP Risk weighted execution pipeline & Gross execution pipeline.

Risk-weighted pipeline 1.8x business target; total pipeline 4.2x 2014 target

Exhibit 24 highlights our forecast of capacity additions by year, against EGP’s risk-

weighted pipeline development rollout (which amounts to 6.4GW over the 2010-2014

period) and its gross pipeline development rollout (which amounts to 14.7GW, including

1.6GW in execution already).

For the risk-weighted estimates, EGP has applied a probability of success to each project

within its pipeline. EGP defines the risk-weighted pipeline as the gross pipeline of all

projects multiplied by a probability of success (90% for highly confident projects, 50% for

likely projects and 20% for potential projects).

We can see that our expected capacity increase of 3.5GW in 2009-2014 (broadly in line

with the company’s target) is supported by a 1.8x risk-weighted pipeline and a 4.2x gross

pipeline.

369 571 724 1,075 767

3,506

4001,100

1,5002,100

1,300

6,400

400

1,400

2,700

5,4004,800

14,700

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2010E 2011E 2012E 2013E 2014E Period 2009PF-2014

MW

GS forecast net capacity additions

EGP Risk weighted execution pipeline

Gross execution pipeline



EGP has the highest ratio of pipeline to targeted growth

Exhibit 25: Enel Green Power has the third largest pipeline versus comps but it has the

highest ratio of total pipeline to targeted annual MW growth Implied years to fully develop pipeline (total pipeline over annualized business plan additions)


Wide geographical and technological diversification

Relative to its peers (with the exception of EDF Energies Nouvelles, which also has more

than 3GW of non-wind pipeline), Enel Green Power’s pipeline is more diversified (both by

technologies and by geography), with more than 3GW from non-wind technologies.

However, in wind, Enel Green Power also has a widespread geographical presence, in

terms of its pipeline and existing assets (the company operates or is building wind farms

in eleven countries).

Exhibit 26: Iberia, North America and Latam have the

largest pipelines Breakdown of pipeline by geography (MW, 1H 2010)

Exhibit 27: Wind the main technology focus for new

capacity; 3GW of solar, hydro and geothermal pipeline Breakdown of pipeline by technology (MW, 1H 2010)



39

33

29

36

31

0

5

10

15

20

25

30

35

40

45


3118

2655

10709

4893

8340150

29865

Italy Europe Iberia Latam North

America

New

Markets

Total

0

5000

10000

15000

20000

25000

30000

35000

Win

d

So

lar

Hyd

ro

Geo

therm

al

Bio

mas

s

Oth

er

To

tal



Net debt/EBITDA at 2.4x leaves more net income than at peers

Enel Green Power has the lowest net debt/EBITDA among the green utilities and its

leverage is also lower than the average of the broader utilities sector. Combined, its high

EBITDA per MW and its low net debt/EBITDA allow Enel Green Power to report the

highest net income among green utilities.

Exhibit 28: Strongest balance sheet among its peers Average net debt/EBITDA; Enel Green Power 2010E data

adjusted for the €3.7 bn loan capitalization by Enel Spa in

March 2010

Exhibit 29: ...leading to the highest net income among

green utilities

2010E net income



Unlike peers, EGP is FCF broadly neutral post capex over 2010-14E

Exhibit 30: EGP is FCF positive post capex over 2010-2014E, unlike peers

FCF for green utilities, post capex, pre dividends and changes in scope of consolidation


1

2

3

4

5

6

7

8

2010E 2011E 2012E 2013E 2014E

EGP IBR EDPR EEN

Acciona Sector average Enel (parent) Iberdrola (parent)

EDP (parent) EDF (parent)

0

50

100

150

200

250

300

350

400

450

500

EGP IBR Acciona EDPR EEN2010E net income, EU

R m

n

FCF (€ bn), pre div 2010E 2011E 2012E 2013E 2014E Cumulative

EGP ‐0.4 ‐0.1 0.1 0.1 0.3 0.1

Acciona ‐0.7 ‐0.2 0.2 0.1 0.3 ‐0.3

IBR ‐0.9 ‐0.5 ‐0.4 ‐0.2 0.1 ‐1.9

EDPR ‐1.0 ‐0.6 ‐0.2 ‐0.1 ‐0.1 ‐2.0

EEN ‐0.6 ‐0.7 ‐0.8 ‐0.7 ‐0.5 ‐3.3



Exhibit 31: Summary data: peer comparison


Valuation: €2/share using multiples & SOTP, in line with sector

In “Opportunities from stock picking: Buy low, sell high; Terna added to Conviction Sell

List”, September 14, 2010, we introduced a new valuation methodology for the utilities.

We combine a short-term valuation based on multiples and a long-term valuation based

on a SOTP or DCF. For Enel Green Power, these valuations combined (50% each) lead to

our 12-month price target of €2, implying 25% potential upside, marginally above the

median of the sector (23%).

Exhibit 32: EGPs 25% potential upside to our €2 12-month target price is close to the

sector median of 23%, and below renewable peers IBR, EDPR & Acciona Potential upside to European utilities sector price targets


EGP IBR EDPR EEN Acciona Average

MW 2010E 6,036 12,516 6,566 2,682 6,723 6,905

MW cagr 2010‐2014E 11% 10% 11% 20% 7% 12%

GWh 2010E 21,597 26,330 14,009 6,020 16,266 16,844

GWh growth 2010‐2014E 8% 14% 15% 21% 8% 13%

Average load 2010E 41% 26% 27% 28% 28% 30%

Renewables EBITDA 2010E, € mn 1,283 1,423 694 388 815 921

EBITDA/MW 2011E 0.21 0.12 0.12 0.15 0.13 0.15

EBITDA/GWh 2011E 0.061 0.054 0.051 0.070 0.055 0.058

Net debt/EBITDA 2010E 2.5 3.4 5.8 7.5 7.1 5.2

WIP (in MW) as of 1H2010 612 1,464 1,317 463 635 898

WIP as % of 2010E installed capacity 10.1% 11.7% 20.1% 17.3% 9.4% 13.0%

Pipeline, MW, 1H 2010 29,865 61,400 32,267 18,378 24,181 33,218

Pipeline to growth (years) 39 33 29 36 31 34

79%

46%

39%37%36%36%35%

32%32%31%31%29%29%

27%26%

20%

28%25%

23%22%22%18%

17%16%14%

10%10%

5%

10%

2%

0%-2%

-8%-12%

-16%

-40%

-20%

0%

20%

40%

60%

80%

100%

ED

F

RE

E

CN

A

AN

A

En

agas

Ed

iso

n

PG

E

ED

P

ED

PR

VE

Gas

Nat

Su

ezE

nv

IBR

PP

C

Sh

anks

En

el

EG

P

En

des

a

Dra

x

E.O

N

Fo

rtu

m

NW

G

CE

Z

Ver

b

IBE

UU

EE

N

SV

T

PN

N

A2A NG

SR

G

Ter

na

SS

E

RW

E



Renewable utilities’ short-term valuations to reflect structural growth

For the renewable utilities, we have adopted a short-term valuation approach based upon

EV/EBITDA multiples and 1-year growth in EBITDA.

Using P/E multiples for renewables may be misleading because of high and varied

depreciation policies on essentially relatively new long-lived assets. Therefore, we use

EV/EBITDA to avoid some of these accounting distortions. We also consider the

short-term (1-year) growth in profit (EBITDA) to reflect relatively high growth rates that

are less likely to be cyclical as a result of growth in the renewables market.

We have considered other high-growth utilities historically when setting target EV/EBITDA

multiples in the context of growth. There is no historical precedent for the renewable

utilities as a result of their short-term listing history (or in Acciona’s case, the short time

period that it has been focused on renewables).

Exhibit 33 shows the relationship between the EV/EBITDA multiple and EBITDA growth for

utilities that have consistently grown EBITDA at a minimum of 10% annually. The

correlation implies the growth multiple should be 8.5x EV/EBITDA plus the growth rate *

10 (e.g. a stock with 20% growth should trade on an EV/EBITDA on 10.5x). Exhibit 34

illustrates the calculated multiples for the five renewable utilities in our coverage,

including EGP, and upside to the “multiples-derived” valuations. Acciona’s base

EV/EBITDA is adjusted downwards as about 25% of its EBITDA does not come from

renewables (and may not have the same sustainable structural growth as renewables).

Exhibit 33: EV/EBITDA vs. 1-year EBITDA growth provides a guide for suitable valuation

multiples for the high-growth renewable utilities EV/EBITDA versus 1-year EBITDA growth for utilities with consistent EBITDA growth of over

10% for 2004-08


y = 9.7919x + 8.5394R² = 0.21

0

5

10

15

20

25

‐10.00% 0.00% 10.00% 20.00% 30.00% 40.00% 50.00%

EV/EBITDA

EBITDA growth (year + 1)

2004‐2008 (high growth stocks only)



Exhibit 34: Appropriate EV/EBITDA multiples for renewable utilities range from

9.5x-11.1x, depending upon short-term growth EV/EBITDA multiple component for renewables’ price targets


SOTP analysis gives €2.1/share valuation

Our SOTP is based on a DCF of each of the different technologies. In EGP’s case, Italian

hydro and geothermal and Spanish wind are the key contributors to valuation. For EGP’s

Italian hydro assets we have assumed all incentives (14% of hydro production in Italy was

incentivized in 2009) expire at end-2015, as suggested by the new draft legislation. We

assume pool prices stay flat at our 2015 estimate of €79 thereafter until the hydro

concessions expire in 2034. Our load factor assumption is 45% with €50k/MW of

opex/maintenance capex. We discount cash flows at 7.5% and assume no terminal value.

For the Italian geothermal business, we assume the same power price and incentive

development as in hydro. We assume load factors of 85% and opex/maintenance capex of

€130k/MW. We assume the plants run until concessions end in 2024. Given EGP’s

significant experience and knowledge in exploiting these geothermal reserves, in our

view it is likely that they will continue to operate these concessions in future. Therefore,

we assume some terminal value for them, equal to our estimate of the NPV of building a

geothermal facility in 2025 or c.33% of capex (€1 mn of NPV for a €3 mn investment).

Exhibit 35: Our SOTP analysis suggests a €2.1/share valuation, with hydro, wind and

geothermal driving the valuation Enel Green Power SOTP analysis


Base EBITDA Target 2011E

EV/EBITDA growth 2012E EV/EBITDA EV/EBITDA

Acciona 8.0x 18% 9.8x 9.2x 24%

EDF Energies Nouvelles 8.5x 26% 11.1x 11.6x ‐11%

EDP Renovaveis 8.5x 19% 10.4x 9.7x 18%

Iberdrola Renovables 8.5x 19% 10.4x 9.3x 19%

Enel Green Power 8.5x 10% 9.5x 8.2x 25%

Upside to current price

based on EV/EBITDA valuation

Enel Green Power SOTP€ mnYE2011 € mn €/share € mn/MW CommentsHydro 5,173 1.0 2.0 In Italy, valuation until end of concessions in 2034, Italy 3,022 assuming all incentives end in 2015 and power price of €79 LatAm 1,614 thereafter. For LatAm, valuation until 2043. No residual Other 538 value for either assetGeothermal 2,763 0.6 3.6 In Italy valuation until end of concessions in 2024, Italy 2,657 assuming all incentives end in 2015 and power price of €79 Other 106 thereafter. Residual value of 33% of capexWind 3,901 0.8 1.3 Assumes 5 yr average age of wind farms. In Italy, assume Italy 724 green certificates until 2015, then fixed tariff of €110/MWhSpain 1,781 1.1 In Spain, assumes power price is capped at €77.5/MWhEurope 637 post 2012Other 759Solar 411 0.1 4.2 High value of solar farms in Italy, assumes €440 solar Italy 319 power remuneration (fixed tariff + pool), and capexOther 92 costs of €2.8/WpOther 226 2.0 Biomass & cogeneration assetsTotal EV Operating assets YE 2011 12,474 2.5

Pipeline & WIP (2012-2015E) 1,010 0.2 Includes NPV of pipeline & work in progress

Solar retail 294 0.1 Using 7x 2011E EV/EBITDA, in line with European SolarTotal Enterprise Value 13,777 2.8 Implied valuation of 9.7x 2011E EV/EBITDANet Debt, including tax liability (3,455) (0.7) Year end 2011 Net DebtMinorities & provisions (918) (0.2) Mostly Enel Green Power España & Fortuna hydro plantAssociates 913 0.2 Mostly wind, solar& waste; valued at 1.4x YE2011E bookRemaining Equity value 10,317Number of shares 5,000Value per share 2.1



For the wind assets, we use the same valuation as for our Iberian renewable coverage

(where Spanish wind farms are remunerated at €77.5/MWh from 2012), without allowing

for upside from higher power prices as we assume some re-regulation in the sector might

occur if power prices start rising, as we forecast. This is despite the Spanish government

recently approving a Royal Decree which reduced wind farm remuneration for two years

(by c.30%), but allows for power price upside in 2013. We are more conservative,

believing rising pool prices are likely to increase pressure on the government to keep

control of costs to consumers. We assume a 5-year average age for existing wind farms

and a terminal value of 15% of initial capex.

Our valuation of the pipeline and work in progress is consistent with our treatment of

growth capital for peers (where we assume growth to 2015, discounting the value created

through investment every year, and then discounting work in progress values from 2015).

Associates and minorities

When valuing Enel Green Power, we need to take into account the value of associates and

also the value of minorities.

Exhibit 36: Associates form a material part of the company’s value

Book value of associates as of 1H2010; €417 mn


We believe any valuation of Enel Green Power should consider the value of its associates

in isolation, rather than as part of the group. Exhibit 36 shows the last reported book

values of Enel Green Power’s associates. In our view, some of these associates could

have a value above their reported book value. For example, the book value of the

geothermal generator La Geo de CV (El Salvador, rated BB by S&P) implies a 2009

EV/EBITDA of only 2.6x, compared to the 5x-8x typical of Latin American utilities. Empresa

do Vale do Minho’s book value also looks low at 6.7x implied 2009 EBITDA, while

Companias Eolica tierra Alta’s implied EV/EBITDA book value implies only 3.3x EBITDA.

Conversely, two associates (Tirme, a waste-to-energy company operating on the Balearic

islands, and ENEOP) have high implied EV/EBITDA multiples. Enel Green Power has

stated that it received an unsolicited offer for Tirme of €80 mn, implying 18x 2009 EBITDA,

while in the case of ENEOP, it has several wind farms currently under construction or

which were completed only during 2009, and therefore its EBITDA was not representative

of is potential underlying cash flow generation in our view.

We value EGP’s associates at €913 mn at YE2011E, or 1.4x YE211E book value. Valuing

minorities based on multiples (10x 2011E EV/EBITDA for EGP España, 12x 2011E P/E for

the Fortuna hydro plant in Panama) implies a c.€750 mn valuation, in line with our

balance sheet figure.

Year to December Country Stake BS value Tech. Capacity Net Debt EBITDA 2009

Asset break down % € mn MW MW, net € mn € mn, net € mn € mn, net

Operating companiesLA Geo SA de CV El Salvador 36% 86 Geo 204 73 (52) (19) 71 26Empr. Eólicos de Alvadia, Lda Portugal 48% 21 Wind 23 11 6 3 4 2Empr. Eólicos de Vale do Minho Portugal 38% 20 Wind 250 95 243 92 44 17Compañia Eólica Tierra Altas, SA Spain 36% 12 Wind 99 36 22 8 17 6Empr. Eólicos de Espiga, SA Portugal 38% 11 Wind 42 16 21 8 7 3

Tirme,SA Spain 40% 18 Waste 30 12 336 134 23 9Eólicas Portugal (ENEOP) Portugal 30% 12 Wind 322 97 281 84 9 3Other minor companies 60 0 0 0 0 0 0Total 240 970 340 857 311 175 65

Developing companies

Elica Greece 30% 137Geronimo USA 25% 22Tradewind USA 41% 18Total including development 417



Exhibit 37: Minorities in Iberia and Panama should also be taken into account Enel Green Power’s major minority stakes (as of 1H2010, the book value of minorities was

€692 mn. Enel Green Power España has c.€150 mn of associates (book value))


Tax equity partnership already treated as debt at Enel Green Power

As of 1H2010, Enel Green Power had €204 mn of US tax equity partnership, which it treats

as third-party debt in its accounts. When using EV/EBITDA in our valuation of Enel Green

Power (and Iberdrola Renovables and EDP Renovaveis) we adjust EV for associates,

minorities, provisions and US tax equity liabilities (for Iberdrola Renovables and EDP

Renovaveis).

Low deferred taxes as €0.5 bn of substitute tax was paid in 2009

Enel Green Power has a low level of deferred taxes relative to its most comparable peers

(Iberdrola Renovables and EDP Renovaveis). Its deferred taxes originate from 2005, when

Enel Green Power’s assets were revalued for fiscal purposes, leading to higher

depreciation charges at EGP (but not at Enel consolidated levels) and to a tax benefit in

the form of deferred taxes. During 2008, Enel Green Power paid a substitute tax (with cash

outflow during 2009) of €517 mn to release €1,039 mn of deferred tax liabilities. This led

to a €522 mn one-off gain in the P&L in 2008 from the release of the deferred tax

provision fund, which we have excluded from our P&L above as it is exceptional.

Enel Green Power’s 2010-2013E EBITDA and net income growth is

lower than green utilities, but higher than the sector average

Exhibit 38: Enel Green power has slower EBITDA growth than renewable utilities ...

EBITDA growth 2010-2013E CAGR for European utility sector


Company Country Asset type and capacity2009 EBITDA

(pro‐forma)Net debt, € mn Minority stake

Enel Green Power EspañaSpain and

Portugal

1.41GW, of which 1.25GW wind, plus

equity stakes (mostly Portugal)180 900 40%

Fortuna Panama 300MW hydro plant 96mn US$ 40mn US$ 49.9%

‐31%

‐12%

‐4%‐4%

‐1%

0% 1% 1% 1%

4% 4% 4% 4% 4% 4% 4% 5% 6% 6% 6% 6% 6% 7% 7% 7% 8% 8%9% 9%

10%10%11%11%

16%16%

21%

24%

‐40%

‐30%

‐20%

‐10%

0%

10%

20%

30%

Drax

PPC

CEZ

RWE

Endesa

International Power

E.ON

Enel

Terna

Severn Trent

EDP

Iberdrola

Snam

RG

National Grid

Verbund

Edison

United Utilities

EDF

A2A

Gas Natural

Pennon

Veolia Environnement

Northumbrian

Water

Centrica

GDF SU

EZ

Enagas

Suez Environnement

REE

Shanks

Fortum

Scottish &

Southern

Polska Grupa Energetyczna

ENEL GREEN POWER

Acciona

Iberdrola Renovables

EDP Renovaveis

EDF Energies Nouvelles



Exhibit 39: ... and has median EPS growth relative to the sector until 2013E EPS growth 2010-2013E CAGR for European utility sector


Exhibit 40: We see 25% potential upside to EGP vs. 23% for the utility sector as a whole – EGP trades at a slight

discount to peers due to slower growth and uncertainty regarding renewable remuneration in Italy, in our view Selected valuation metrics for Enel Green Power and other renewable utilities

All share prices in euro

Source: Goldman Sachs Research estimates. For important disclosures, please go to http://www.gs.com/research/hedge.html.

We do not view EV/MW as an appropriate valuation methodology as a result of

significantly different levels of profitability. We view EV/MWh as a potentially better peer

comparison methodology. We expect Enel Green Power’s profitability per MW and per

MWh to remain above those of IBR and EDPR throughout our forecast period (see

Exhibits 20 and 21).

‐35%

‐19%

‐11%

‐6%‐6%‐4%

‐2%‐2%‐2%‐1%

2% 3% 3% 3%

6% 7% 7%9%10%10%11%11%

11%12%13%13%13%14%

14%14%15%16%

21%

31%32%33%

‐40.0%

‐30.0%

‐20.0%

‐10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

Drax

RWE

CEZ

Endesa

Terna

E.ON

EDP

Enel

Snam

RG

National Grid

Gas Natural

International Power

Iberdrola

Enagas

REE

ENEL GREEN POWER

GDF SU

EZ

Scottish &

Southern

Suez Environnement

Severn Trent

Verbund

Centrica

A2A

Edison

Fortum

Northumbrian

Water

EDF Energies Nouvelles

EDF

Pennon

Polska Grupa Energetyczna

United Utilities

Veolia Environnement

Iberdrola Renovables

Acciona

Shanks

EDP Renovaveis

Current Potential EV/EBITDA 2011E 2012E P/E CROCI

Valuation Comparison Rating share price upside 2010E 2011E 2012E 2013E at target price 2010E 2011E 2012E 2013E 2010E 2011E 2012E 2013E

Acciona Buy 55.5 37% 10.0x 9.2x 7.9x 6.9x 10.3x 8.8x 22.3x 20.2x 12.8x 9.9x 5.8% 6.1% 6.8% 7.5%

EDF Energies Nouvelles Neutral 31.8 10% 13.3x 11.6x 10.3x 9.5x 11.9x 10.6x 21.8x 19.3x 15.8x 15.0x 7.1% 7.3% 7.7% 7.9%

EDP Renovaveis Buy 4.4 32% 11.2x 9.7x 8.5x 7.9x 11.0x 9.7x 48.4x 36.4x 22.9x 20.7x 5.0% 5.8% 6.6% 6.9%

Iberdrola Renovables Buy 2.6 29% 10.1x 9.3x 8.1x 7.1x 11.1x 9.6x 25.5x 21.9x 17.5x 14.5x 6.8% 6.7% 7.0% 7.2%

Enel Green Power Neutral 1.6 25% 9.5x 8.2x 7.5x 6.8x 9.4x 8.7x 17.3x 18.0x 16.4x 14.1x 6.8% 6.8% 7.0% 7.2%



High exposure to power prices, particularly in Italy

Enel Green Power is exposed to wholesale power prices, particularly in Italy (where

it produces 12TWh of power exposed to market prices) and, to a lesser extent in

Spain (3TWh exposed to market prices). Thus, almost 70% of its production is

exposed to power prices. In Latin and North America, most of its power is sold

under fixed feed-in tariffs or PPAs (except for Panama). EGP has no or immaterial

exposure to power prices in France, Greece and Portugal, as its power is sold under

feed-in tariff contracts.

Exhibit 41: Enel Green Power is highly exposed to wholesale power prices (as a result of

higher fuel costs) Unhedged exposure of EBITDA and net income to power prices to a €10/MWh change in power

prices globally (as a result of higher fuel commodity costs).


European power prices show a strong correlation with Brent…

European power prices are all strongly correlated with each other and historically have

been strongly correlated to the oil price (Brent) as this is the main variable determining

the evolution of input costs such as gas (and CO2). This correlation broke down during in

2009 and 2010 as a result of gas oversupply, which allowed cheap spot gas to flood the

European market, thus depressing CO2 and power prices. We remain of the view that the

European gas market will return to balance by 2012, and we therefore expect European

power prices to regain their historical correlation with oil. For more on this please see,

“European gas fundamentals have bottomed”, December 31, 2009.

…and are occasionally impacted by weather

Occasionally, weather conditions can also influence day-ahead prices. This was the case

in 2006 in Spain (a dry year, which pushed day ahead prices above German levels) and

1H2010 (the second wettest year of the decade, which pushed prices during many off-

peak hours to zero). While Enel Green Power has the option to sell some of its power

Total clean

generation (ex

Spain wind); Net

Income

Total clean

generation; Net

Income

Total clean

generation (ex

Spain wind);

EBITDA

Total clean

generation;

EBITDA

Verbund 29% 29% 22% 22%

Fortum 23% 23% 17% 17%

EGP 17% 22% 8% 11%

E.ON 17% 17% 9% 9%

CEZ 16% 16% 9% 9%

EDF 13% 13% 5% 5%

Endesa 13% 13% 5% 5%

Edison 12% 12% 4% 4%

RWE 12% 12% 5% 5%

Iberdrola 11% 14% 6% 7%

Enel 9% 10% 4% 4%

GDF SUEZ 8% 8% 4% 4%

PPC 8% 8% 3% 3%

Acciona 8% 42% 2% 10%

A2A 8% 8% 4% 4%

EDPR 8% 26% 2% 6%

SSE 5% 5% 3% 3%

Gas Nat 5% 6% 2% 2%

IBR 5% 18% 2% 7%

EDF EN 5% 5% 2% 2%

Centrica 4% 4% 3% 3%

EDP 4% 6% 1% 2%

IPR 2% 2% 1% 1%

PGE 1% 1% 1% 1%

Drax 0% 0% 0% 0%

% change due to €10/MWh higher prices on:



forward (within or outside the Enel group), it remains at least partially reliant on the spot

price as its production (particularly wind) is intrinsically unreliable. In Italy, 20% of power

is sold on a spot (day-ahead) basis. In Iberia this figure in 1H2010 was 65%, though in our

view Enel Green Power España might try to reduce this in the future through supply

agreements with the Endesa group.

Exhibit 42: Spanish and German wholesale power prices historically strongly correlated;

Italy at a premium Day-ahead power prices

Source: GME, Datastream, Goldman Sachs Research.

We expect European wholesale power prices to increase from 2012

Exhibit 43: Our forecasts point to higher wholesale power prices in Italy and Spain on the

back of rising commodity prices


Italian prices – high and likely to stay well above European levels

In Italy, which currently enjoys higher wholesale prices than the rest of Europe, wholesale

prices are unlikely to fall over the next five years, in our view. We expect a higher

hydrocarbon prices and a rising CO2 price (we assume €25/tonne) longer term to drive

prices higher. Therefore, despite recent investment in new capacity having brought the

reserve margin to over 26% in 2009 (source: Terna), we expect wholesale power prices to

rise, particularly from 2012, on the back of higher oil and gas prices and higher CO2 prices.

0

20

40

60

80

100

120

0

10

20

30

40

50

60

70

80

90

2004 2005 2006 2007 2008 2009 2010 to Nov.

US$/bl

EUR/M

Wh

Italy Germany Spain Brent/ €bbl

Year to December 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E

Assumptions

Italy baseload power price 75 71 87 64 64 72 73 78 83 79

Spain baseload power price 51 39 64 38 37 42 57 62 66 68

German baseload power price assumption 50 50 49 55 55 58 68

Italy - Germany price differential 23 18 23 25 11

US$/€ 1.30 1.35 1.47 1.39 1.35 1.35 1.35 1.35 1.35 1.35

CO2, €/tonne 15 1 22 12 15 20 25 25 25 25

Oil, $/bbl 65 70 98 62 79 85 85 85 85 85

Green certificate cost, €/MWh 4 4 4 4 4 0

Green certificate, €, avrg traded price 119 88 88 89 89 76 75 72 68 71



Exhibit 44: Italian wholesale power prices have been driven by oil prices (Brent); we

expect this to continue Italian and German wholesale power prices and Brent in €/bbl (forecasts in dotted line)

Source: GME, Goldman Sachs Research estimates.

Italian power prices remain linked to Brent

Italian power prices have been linked historically to the evolution of Brent. This is because

the vast majority of gas imported into Italy and burnt in thermal power plants is linked

through formulas to Brent and its derivatives, typically with a 6 or 9-month lag (which

partly explains also the lag in 1H2010).

Italian wholesale prices have consistently traded above German levels

In the following exhibits we show that day-ahead power prices have remained

consistently higher in Italy than in the rest of Europe (we take Germany as a benchmark),

despite large investments in new capacity in recent years (see Appendix).

Exhibit 45: Italian wholesale prices have been

consistently €20/MWh above German prices since 2004…Italian versus German day-ahead wholesale power prices

Exhibit 46: ...and remained so into 2010; the gap has

widened in recent months Italian versus German day-ahead wholesale power prices



0

20

40

60

80

100

120

0

10

20

30

40

50

60

70

80

90

2004 2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E

US$/bl

EUR/M

Wh

Italy baseload power price Oil, $/bbl

0

10

20

30

40

50

60

70

80

90

2004 2005 2006 2007 2008 2009 2010 to Nov.

EUR/M

Wh

Italy Germany difference

0

10

20

30

40

50

60

70

80

90

Jan Feb March April May June July Aug Sept Oct Nov

EUR/M

Wh

Italy Germany difference



Why are Italian wholesale prices above northern European levels?

Despite large investments in new capacity and a nameplate reserve margin, we believe

there are at least four specific reasons why Italian prices could remain above German or

central European levels in the medium term:

Generation mix, as Italy still relies heavily on imported oil-linked gas for its power generation. As a result of infrastructure bottlenecks, spot gas has a difficult

time reaching Italy. In our view, this currently explains at least €5-10/MWh of the

difference between Italian power prices, relative to German prices. We expect this

spread to gradually decline as more gas import infrastructure is built, but not before

2015, and expect Italy to continue to have a €0-5/MWh premium to northern Europe

through the rest of the decade given the poor transport infrastructure.

Specific rules in the Italian wholesale power market, where thermal generators (which

set the marginal price) have also to pay an additional cost of pollution as they are required to buy green certificates, thus adding a variable cost. Considering

the current green certificate price and the quota obligation for 2010 of 6.05%, this

additional cost currently equates to c.€5.4/MWh. The Italian government has recently

announced that it will phase out the green certificate system from 2013 to 2015,

replacing it with feed-in tariffs for renewables. We do not believe that these will have

an impact on wholesale prices (as it is not a variable cost for generators) and we

expect to see this €4-5/MWh premium removed from the Italian price. In our

estimates we reflect this in 2015 through a €4/MWh yoy fall in power prices.

The shape of the Italian wholesale market (which is significantly more “peaky”

than northern European markets), leading to higher prices at peak when less efficient

plants are used. Although the addition of solar capacity might mitigate this

phenomenon in the future, we doubt it will disappear (summer peaks are now as high

as winter peaks and thus Italian reserve margins are some 10% lower in summer than

in winter). In 2010, peak summer demand was up 9% yoy, exceeding 56,000MW, as

the rising peaks are also a result of air conditioning which is becoming more

widespread. We estimate this peaky shape adds €2-5/MWh to the Italian wholesale

price, relative to Germany, as less efficient plants are used during this period.

Exhibit 47: In Italy, the summer peak (close to 52,000MW in 2009) equals the winter peak,

unlike in the rest of Europe, yet during the summer less capacity is available

Source: Country system operators, Terna for available capacity.

It is worth noting that, from a national security of supply perspective, the high summer

peaks make solar developments more attractive in Italy.

Electricity grid bottlenecks (particularly congestion in the Sicilian and Sardinian

grid), which add €2-4/MWh to the average national price, are unlikely to be eliminated

before 2015. Beyond that, assuming that the upgrades to the transmission grid are

completed, we would expect a €0-2/MWh premium due to congestion, given the

morphology of Italy. This is also particularly relevant for renewables, as wind (and

solar) receive a zonal price (i.e. a wind farm in Sicily would achieve a higher price

while still having the same right to make additional revenues from green certificates).

Ratio of summer peak to

winter peak

Capacity available at

summer peak (2009), MW

Capacity available at

winter peak (2009), MW

South Australia 1.43

California 1.43

Texas 1.30

Italy 1.00 65,604 70,009

Spain 0.91

Poland 0.78

UK 0.75



Exhibit 48: Same national price, but different by regions: lower in the north, higher on

the islands where most of the wind capacity is concentrated


We expect a €9-23/MWh premium to Germany to be sustainable for Italy through 2015; €2-12/MWh premium after that appears reasonable

In total, we believe wholesale power prices in Italy can remain at a €9-23/MWh premium

to the European price through 2015, and a €2-12/MWh premium thereafter (assuming no

green certificate costs, and that gas and electricity grid investments are completed on

time).

Exhibit 49: We expect Italian wholesale power prices to remain at a premium to Germany

The new law for renewables is expected to phase out green certificates between 2013 and 2015.


Italy heavily reliant on gas (and oil-linked gas contracts); lack of base-load generation (no nuclear)

Historically, high Italian electricity prices have reflected Italy’s reliance on energy imports

(>80% of primary energy), its abandonment of its nuclear programme in the 1980s

following a public referendum on nuclear (after the Chernobyl disaster) and a lack of

domestic coal reserves and limited gas reserves (leading to limited coal and gas-fired

generation). Instead, the largest source of power generation in the 1990s was fuel oil,

which represented over 40% of all the thermal generation in 1999 (the year of sector

liberalization), a percentage which in 1995 was as much as 60%. In 2009, gas and fuel oil

generation still represented almost 50% of the total national generation.

50

60

70

80

90

100

110

120

2005 2006 2007 2008 2009 Jan‐Aug 10

EUR/M

Wh

Sicily Sardinia Italian baseload Northern Italy

Italian vs. German price differential 2010‐15E 2016E‐beyond

Gas price 5‐10 (or more) 0‐5

Green certificate 0‐4 0

Peaking requirements 2‐5 2‐5

Grid bottlenecks 2‐4 0‐2

Sum, €/MWh 9‐23 2‐12



Exhibit 50: High-cost gas and oil-based represent almost 50% of Italian gross power

generation, coal only 12%, hydro 16% and nuclear 0% Italian gross power generation and imports in 2009, TWh (total value 337 TWh)

Source: Terna, Goldman Sachs Research estimates.

A superficial view of the reserve margin suggests Italian power prices may be unsustainable after recent strong investments

Since 2002, the Italian power sector has added over 34GW of new, high efficiency gas-

fired plants (CCGTs), 17GW since 2005. During 2009, according to Terna data, Italian

power demand peaked at 52GW, yet Italy enjoyed a 26% reserve margin in the summer

and a 37% reserve margin in the winter peak. Despite this, Italian power prices remain

stubbornly above European power prices and we expect this to continue. We believe that

the large capex cycle for new CCGT has substantially been completed as companies

prioritize paying down debt, and the system has adequate spare capacity.

Fuel oil has been providing expensive reserve margin to Italy

Following the increase in oil prices from the middle of the last decade, the use of fuel oil

plant started becoming prohibitively expensive (with prices above €100/MWh or even

€150/MWh). However, Italy had fortuitously started a major programme of upgrading its

generation fleet by building over 30GW of gas-fired CCGTs over the decade.

Now new and old gas plants set prices at the peak

We believe a more appropriate view of the evolution of Italian reserve margins excludes

fuel oil generation. Margins on these terms reached positive values only from 2008. If we

exclude also older gas plants (Exhibit 51), the percentage becomes barely positive only

from 2009, implying that old simple-cycle (or some of the older and lower efficiency)

CCGTs are still required to provide power during peak times, often demanding prices in

excess of €100/MWh.

Hydro

16% Other

renewables

3%

Imports

13%

Coal

12%

Other fuels

7%

Gas

44%

Oil

5%



Exhibit 51: Italian reserve margins (2000-2015E) gradually improved as fuel oil plants

have been replaced by CCGT; new investments or new interconnectors required by 2015-

2018 We assume a 2.5% pa growth in the Italian peak power demand


We expect no further major CCGT programmes as companies pay down debt

Most of the planned new CCGTs have now been completed, with less than 3GW currently

under construction according to our estimates. In our view, the Italian large replacement

programme has stopped just ahead of a shift to oversupply.

Exhibit 52: Most new CCGTs have already been added – few more expected

Additions of new CCGTs in Italy since 2000 (see appendix for more details)


As all major players in Italy (Enel, Edison, A2A, Eon, Sorgenia-Verbund) are currently

focused on preventing increases in their debt levels, we believe that a further phase of

investments is unlikely. Instead, we believe companies will try to generate cash from

existing plants and pay down debt for at least a few years. Several plants, which were

planned to start in 2010 or 2011 appear to be on hold (for example A2As’ Monfalcone

repowering). Thus, Italy should continue to rely marginally on older, lower efficiency

-60%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E

Avai

labl

e C

apac

ity le

ss P

eak

Dem

and

as %

of P

eak

Dem

and

Reserve margin Reserve margin excluding interconnectors Reserve margin excluding fuel oil and old gas

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2002

2003

2004

2005

2006

2007

2008

2009

2010E

2011E

2012E

2013E

Gas (CCGT) Coal



CCGT (with efficiency of 45%-52%) or even simple-cycle plants (with efficiency of

42%-43% or less) to supply power during peak times.

New import pipeline planned for Italy to bring cheaper gas, but not before 2016

Another possible reason for the lag between the Brent price and Italian power prices in 1H

2010 could be the shipment of some cheaper spot gas to Italy. While Italy has limited LNG

import facilities (two terminals, for 12bcm of capacity pa; a third one of 3bcm/pa is due to

be completed at the end of 2011), there are several projects to expand this capacity. Two

new pipelines are planned for Italy (one via Algeria, Galsi, and another connecting Italy to

Greece, IGI, to bring gas from the Middle East or the Caucasus), though as a result of

administrative delays neither is likely before 2016, in our view. A fully authorized LNG

terminal is also planned by Enel in Porto Empedocle, near Agrigento, Sicily, however we

do not expect this to be built before 2015 at the earliest.

No excess gas supply in Italy this winter

As a result of the lengthy authorization process, we do not see looming gas overcapacity

for Italy. Over the next twelve months Italy might even face a gas shortage. The

Transitgas pipeline, which delivers gas to Italy from northern Europe via passo Gries, and

represents 18% of national import capacity (up to 24bcm/pa maximum) went offline in the

summer following an avalanche in Switzerland which has damaged the pipeline. In 2009,

it delivered to Italy 12bcm of gas, or 15% of total consumption. This implies that there will

have been no excess gas in Italy through the current winter period.

Spain: we expect prices to rise (but also political intervention)

Contrary to the situation in Italy, Spain has experienced a significant fall in wholesale

power prices, to a significant discount to German price levels, on the back of overcapacity,

competitive gas sourcing and, in 1H2010, adverse weather. Higher gas and CO2 prices are

likely to have a positive effect on the Spanish power market in our view, yet in our

assumptions we do not expect the government to allow wind farms to benefit from higher

power prices. Should this not happen (and recently approved legislation remained

unchanged) wind farms could benefit from rising power prices.

Most of the wind production is under the old regime and unhedged

In Spain, Enel Green Power produces close to 3TWh, mostly from wind. In 1H2010, 67% of

Enel Green Power’s production in Spain (from 939MW of installed capacity) was

unhedged. All of this production was linked to the RD436 legislation (transitory

disposition), which allows the wind farm to receive a €38/MWh premium over the pool

price until 2012 inclusive (instead of the €31/MWh premium for new wind farms), but does

not benefit from floors (and is not subject to caps).

Exhibit 53: Only 35% of Iberian 1H production was hedged


Iberia, 1H2010 No plants MW GWh % ot total

RD661 ‐ Pool + premium, with cap&floor 3 82 71 6%

RD661 ‐ fixed tariff (wind €77.5/MWh) 33 259 249 21%

PPA (Portuguese assets) 26 128 98 8%

Total hedged 418 35%

RD 436 ‐ Pool + €38/MWh premium for wind 51 939 740 65%

Total 113 1,408 1,158 100%

of which wind is 80% of total production 1,246 931



Focus on renewable capacity growth in selected regions

EGP’s presence in the renewable energy market exposes the company to growth

opportunities. Globally, renewable energy generation (ex. hydro) has experienced a 26.2%

CAGR in installed capacity over the last five years (source: BP statistical review of world

energy) as governments in the OECD and emerging markets institute policies to support

renewable technologies. For example, the EU directive on renewable energy (2009/28/EC)

requires member countries to source 20% of primary energy consumed from renewable

sources by 2020 and achieve a 20% reduction in CO2 emissions (from a 1990 base) – the

so called triple 20.

28% of global installed capacity and growing

Exhibit 54: With 1,225 GW renewables are 28% of the global installed generation capacity

Global renewable electricity generation capacity as of 2009, includes all hydro

Source: Enel estimates based on WEO2009/GWEC 2008 (2008); WEO 2009 reference scenario (2020 min)l industry reports/McKinsey (2020max); Ren21 “Rapporto Renewables Global Status” 2009-2010; For Nuclear, Thermal & Total World data from EIA (data from 2007).

Similarly, China is targeting 330GW of hydro (including large hydro) and 150GW of wind

power by 2020, from 196GW and 16GW in 2009 respectively. In the US, different

legislative proposals (none of them signed into law) target a 17%-20% renewable energy

requirement at the federal level by 2020 (ex. large hydro), vs. c.3% in 2009. Currently, 29

US states have state-wide renewable electricity requirements. In our view, the key drivers

of increased support of renewables are:

Environmental concerns, particularly climate change. Power generation is the largest

source of green house gas emissions globally and we expect increasing momentum to

limit growth in emissions. Our analysis suggests over one-third of global generation

capacity will need to be zero-carbon by 2030 to meet emission reduction targets (GS

SUSTAIN).

Security of supply. The OECD imported 59% of its energy needs in 2009 (Source: IEA).

Renewable energy power generation is intrinsically local (e.g. hydro, wind, solar,

geothermal) and therefore can help mitigate supply risk and increase diversification in the

power generation portfolio and create local jobs.

High and volatile commodity prices, falling LCEO for renewables. Volatility of energy

commodity prices and their levels have risen materially in the last decade, and although

wind and solar power continue to be more expensive than hydrocarbon-based power,

980

159 54 21 11

1,225

379

2,968

4,429

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Hyd

ro

Win

d

Bio

mas

s

So

lar

Geo

ther

mal

Tota

l re

new

able

s

Nuc

lear

Ther

mal

Tota

l wo

rld

GW



these are becoming more competitive. Improving technology has dramatically reduced

the levelized cost of energy for both wind and solar PV, where panel prices have fallen

more than 50% in the last two years alone. Improvement could continue to reduce the

relative costs of renewable alternatives, with small hydro and geothermal already cost

competitive.

New renewable capacity could grow 130%-550% by 2020 (ex.

hydro)

Growth in renewable energy is highly correlated with supportive regulation. External

bodies such as the IEA suggest varying degrees of expansion in renewable capacity

depending on policy outcomes. Exhibit 55 highlights Enel’s estimates, based on these

reference scenarios (which are broadly in line with our estimates: that one-third of global

generation capacity will need to be zero-carbon by 2030 to meet emission reduction

targets).

Exhibit 55: Global renewable energy capacity could grow 50%-150% by 2020 depending

on different regulatory outcomes Current renewable capacity (2009) vs. min and max 2020 scenarios

Source: Enel estimates based on WEO2009/GWEC 2008 (2008); WEO 2009 reference scenario (2020 min)l industry reports/McKinsey (2020max); Ren21 “Rapporto Renewables Global Status” 2009-2010.

Using Enel’s estimates (based on external sources), we calculate renewable (ex. hydro)

could grow between 130% and 550% depending on regulation. Including hydro (which

has a much larger installed base) growth could be 50%-150% to 2020.

Wind, solar and geothermal combined 5-year CAGR of 26%

Growth in installed capacity has been material for wind and solar, both relative

newcomers to the renewable space compared to geothermal and hydro power. Globally,

wind installed capacity has grown at a 27% CAGR in the last five years (by 111GW) and

solar by 43% (19GW). This contrasts to a 3.8% 5-year CAGR for geothermal power

capacity (1.8GW) and a 3.2% 5-year CAGR for hydro electricity production (although this

has supplied a further 474TWh of energy due to the large base).

1,225

243 16435

407 376

1,820

330200

70

620 600

3,020

550

330

110

1,030 1,000

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Total world North America Latin America Africa Europe Asia

GW

2009

2020 min

2020 max

EGP focus regions EGP focus region



Exhibit 56: Wind, solar and geothermal combined installed capacity 5-year CAGR of 26%

Cumulative installed capacity for wind, solar and geothermal

Source: BP statistical review of World Energy 2010.

Exhibit 57 highlights the relative competitiveness of power generation technologies on a

levelized cost of electricity basis (LCEO), with no subsidies or carbon costs. This helps

identify the cost of different generation technologies, normalizing for differences in

up-front capital costs vs. ongoing fuel costs. Typically renewable energy (solar, wind,

geothermal, hydro) tends to have high up-front capital costs, with low or zero marginal

costs, as the fuel costs are zero. This is also true for nuclear energy, where fuel costs are

small compared to up-front capital costs. Conversely, both coal and gas plants tend to

have ongoing fuel costs, which as evidenced through 2006-2009 can be very volatile.

Wind becoming commercially competitive from €80/MWh

Exhibit 57: Hydro and geothermal technology is very competitive, wind close behind

Levelized cost of electricity (LOCE) for different generation technologies; average European

S

olar PV €2.2-2.9/W & 15% load factor, Solar thermal €4.5/W & 24% load, Wind €1.3/W & 24% load, Natural gas €0.6/W, 65% load (fuel

cost €32/MWh current, €55/MWh long term), Nuclear €5/W & 90% load, Coal €1.2/W & 85% load (fuel cost €32/MWh); Small hydro €2/W

& 46% load, Geothermal €3/W & 85% load factor. All analysis uses a 7.6% WACC, no CO2 costs, no production or investment subsidies


0

50

100

150

200

250

2003 2004 2005 2006 2007 2008 2009

GW

cum

mul

ativ

e in

stal

laed

cap

acity

Wind

Solar

Geothermal

€0

€50

€100

€150

€200

€250

€300

€350

PV -residential

Solar thermal PV -commercial

PV - utility Wind Natural gas long term

Small Hydro Geothermal Nuclear Coal Natural gas current

€/M

Wh

Average baseload electricty price



Our LCEO analysis indicates that geothermal energy is on average already one of the

cheapest forms of generation, even compared with traditional hydrocarbon-based energy

at current commodity costs. The economics of hydro power are equally compelling

(c.€60/MWh). We estimate wind has an LCEO of €80/MWh (assuming a good location),

higher than current hydrocarbon base-load or nuclear power, but only marginally so.

Indeed, during the period of high commodity prices in 1H2008, wind power’s LCEO was

lower than traditional hydrocarbon-based generation in many European countries.

Adding CO2 costs to thermal would make renewables more competitive

Exhibit 57 uses current coal costs of €32/MWh and shows two scenarios for gas prices,

the first consistent gas price in Europe through the summer (equal to €32/MWh on an

average of fuel costs) and the second using €55/MWh (more consistent with our long-

term bullish view on gas prices). We highlight that our analysis assumes load factors of

65% for CCGT, while currently certain regions (like Iberia) have much lower loads, largely

as a result of a strong increase in renewable power supply (with priority of dispatch) and

lower demand due to the poor economic environment.

On our long-term assumptions, gas is close to the LCOE of wind power. In addition,

European thermal generation also faces additional CO2 costs, currently €12-15/MWh for

coal and €5/MWh for gas. The only renewable technology that remains materially more

expensive than hydrocarbon-based power is solar. However, as we have mentioned

previously, solar panel prices have fallen 50% over the last two years, and if we continue

to see this rate of decline going forward, solar’s LCOE will improve materially. For our

solar PV analysis we use a 15% load factor as a European average, however, areas with a

significant amount of solar radiation (such as southern Italy or Spain) can see load factors

closer to the high teens.

Recent agreement for the supply of 1.3GW of turbines

As part of Enel Green Power’s growth plans, it has signed a framework contract for wind

turbine supplies with two leading global suppliers, for 1.3GW from 2011 to 2014, with an

option for a further 1.3GW. This allows substantial coverage of its wind capacity roll out

(we forecast 2.7GW of added wind capacity for the period), allowing for flexibility of

delivery location with fixed or limited indexation in prices. Furthermore, warranties will

cover availability, O&M and power curve efficiency and EGP will be able to access the

latest technology from the turbine suppliers. EGP has stated it secured 10% lower prices

vs. those achieved in 2009.



Italy and Iberia are key for growth, Europe and Americas follow

3.5GW of additions planned by 2014, well covered by the pipeline

Enel Green Power is targeting the addition of 3.5GW of renewables by 2014,

bringing its installed capacity to 9.2GW. At its FY2010 results, Enel provided details

of this, indicating that it expects to add 0.8GW in Italy, 1.2GW in Iberia and 1.5GW in

the rest of the world over the period. While wind should represent more than 85% of

the planned installation, it should represent only two-thirds of the total capex, with

the remainder focused on hydro, geothermal and solar; these are more capital-

intensive but also have higher load factors.

Exhibit 58: Enel Green Power has a diversified pipeline globally (1H2010) Not to scale; projects under construction or in execution. Excludes solar (32MW currently under construction in Italy and 7

under execution, different locations; small hydro in Italy 3MW (different locations) and a 1MW mini-hydro plant in Chile.


Under construction

Ready to build

Castle Rock Ridge (76)

Caney River (200)

(MW)

Valdihuelo (16)Lanchal (21)

Pucheruelo (23)Padul (9)El Puntal (13)

Los Barrancos (20)

Alto do Marco (12)

Alvaiazere (10)

Sources de la Loire (12)Haute de

Conge (26) (completed)

Cogollos (50)Valdelin (9)

Valdelin expansion(3)

Eneop (52 + 85)

Charmoy (10)Coulonges (36)

Cara Constantine (10)Dealul Pietros (24)

Salbatica 1(70)

San Pietro Avellana (10)

Hlogos (20)Prophet Helias (10)

Martinou (6)

Trapani Contrada Coniglia (21)Bagaladi (12)

Montebello Jonico (21)

Aquilon (50)

Maida (44)Maida expansion (12)

San Floro (8)

Wind

Hydro

Geothermal

Chucas (50)

Palo Viejo (85)

Energiaky (6)Kastiantiko (2)Pougakia (1)

Cove Fort (17)

On drilling

Apacheta (40)El Zouquete (40)

Radicondoli GR_1 (16)Chiusdino (17)



Exhibit 59: Most of EGP’s capacity expansion is likely to

happen in wind... GS expected capacity addition by technology, broken down

by stage of development (# at top is total)

Exhibit 60: ... with capacity additions having a good

geographical mix; Iberia the largest region GS expected capacity addition by region, broken down by

stage of development (# at top is total)

Source: EGP data: Ready to build & under construction figures, Goldman Sachs Research: total estimates.

Source: EGP data: Ready to build & under construction figures, Goldman Sachs Research: total estimates.

Italy – we expect 0.8GW of capacity additions by 2014

Italy is EGP’s core market. It represents 47% of its installed capacity (in MW as a

percentage of 2009PF) and we expect the company to add 722MW through to 2014, 21%

of total additions. As a result of the high load factors of its Italian capacity (hydro,

geothermal), Italy represents 56% of power output (in MWh as a percentage of 2009PF),

falling to 45% in 2014E. Exhibit 61 highlights the split of total Italian renewable installed

capacity (ex. large hydro) as of 2009. Exhibit 62 shows the additions we expect in Italy.

Exhibit 61: Italy’s renewables capacity is 10.9GW ... Make up of Italian renewable power capacity (small hydro

only), as of 2009

Exhibit 62: ... with EGP at 2.6GW, growing to 3.4GW by

2010 according to our estimates GS expected capacity additions to 2014 by technology, Italy

Source: EGP based on EER “Global renewable power generation forecast 2010-2015).

Source: EGP data: Italy 2009PF, Goldman Sachs Research estimates.

Italy targets 29% of electricity from renewables by 2020 from 17% today

In Europe, the key regulatory driver for investment in renewables is the European

directive 2009/28/EC which fosters the use of renewable energy sources. The directive sets

binding targets for the EU to reach 20% of total energy use from renewables, with the

target varying for each member country. Italy’s target is to derive 17% of its total energy

use from renewables by 2020 (from 8.7% as of 2006). To help reach this target, the Italian

Ministry for Economic Development’s draft national action plan sets a specific target for

final gross electricity consumption of 28.97% from renewables by 2020, from 16.58% in

2008 (source: Minister dello Sviluppo Economico, June 11, 2010).

509 630

543643

1,962

2,232

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Hydro Geothermal Wind Solar Total

MW

Future development

Ready to build

Under construction 3,014

218105170

3,505

162 72 216 85 76

611157200

610

579272

835

231367

2,284

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Italy Europe Iberia Latin America North America Total

MW

Future development

Ready to build

Under construction

3,505

643

367

1,208

505

782

4,900

10,900

2,700

700

1,000

1,600

0

2,000

4,000

6,000

8,000

10,000

12,000

Wind Small hydro Geothermal Solar Other Total

MW

429

3,419

1509

548

24 48

162

695

4

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Italy 2009PF Wind Small hydro Geothermal Solar Italy 2014

MW



Further to climate change legislation, security and diversification of supply and fuel price

volatility are further drivers of the Italian market. Italian renewables are compensated

mostly through a tradable green certificate (GC) system, set to be replaced by feed-in

tariffs from 2013 to 2015.

New renewables to receive feed-in tariffs from 2013, phasing out of GCs

The Italian government recently announced a change in the remuneration system for

renewables in Italy. All new plants (from 2013) will receive a fixed feed-in tariff power

price to be determined by an auction. The government will set a minimum price to

guarantee investment. Under the current system, renewables receive tradable certificates

(GC) on top of the power price which together are c.€150-160/MWh. We expect feed-in

tariffs to set remuneration levels lower than the current system, but could provide greater

certainty in terms of timeframe. In our estimates, we assume hydro and geothermal

receive compensation in line with our 2015 forecast pool price of €79/MWh. This still

allows new hydro and geothermal plants to have an IRR of 9%-11% in our estimates. For

wind, we expect €110/MWh feed-in tariffs, consistent with a 7.5% return and in line with

returns we assume for the Spanish market.

Italy: energy dependency and high energy prices make renewable attractive

We believe policy will continue to support renewables expansion in Italy as it will not only

allow Italy to reach its renewable energy quotas (as mandated by the EU), but will also

help reduce energy dependency (Italy is a large net importer of fuel) and thus reduce

imports. In addition, investments in renewables can assist the economic development of

Italy’s southern regions, in line with long-term Italian government objectives.

Most renewable projects are in the south of Italy

While geothermal is present in only one Italian region, Tuscany, hydro and other

renewables are spread across the country. In the case of wind, which received 32% of the

national green certificates in 2009 (with the rest going to (mini)hydro, geothermal and

biomass), southern Italy is the region of choice, also as a result of greater wind availability.

According to Terna, more than 96% of the planned wind capacity through 2015 is likely to

be built in the Italian southern regions or on the islands.

Exhibit 63: Expected Italian wind capacity by region: 96% in the southern regions

Terna’s expectation of installed wind capacity by 2015, by region. Total expected 10,260MW

Source: Terna.

Sicily23%

Sardinia13%

Puglia24%

Campania14%

Calabria11%

Abruzzo3%

Basilicata4%

Molise4%

Other4%



Exhibit 64: EGP Italian installed capacity and production data by technology


Iberia – 1.2GW by 2014E (0.8GW in Spain, 0.4GW in Portugal)

Iberia is EGP’s second largest market (24% of installed capacity in MW as percentage of

2009PF) and we expect the company to add 1,208MW to 2014 (35% of total additions). As

of 2009PF, Iberia represented 14% of production, as the vast majority of MW were wind,

with relatively low load factors. We expect Iberia to represent 20% of production in 2014.

Exhibit 65 shows the split of total Iberian renewable installed capacity (ex. large hydro) as

of 2009. Exhibit 66 illustrates the additions we expect EGP to make in Iberia.

Exhibit 65: Iberia’s renewables installed capacity was

29.4GW as of 2009, of which 75% was wind Make up of Iberian renewable power capacity (small hydro

only), as of 2009

Exhibit 66: We expect EGP to add 1.2GW by 2014, with

the vast majority of additions in wind GS expected capacity additions to 2014 by technology, Iberia


Source: EGP data: Iberia 2009PF, Goldman Sachs Research estimates.

Spain targets 38% of its electricity from renewables by 2020

As in Italy, the EU renewables directive is a key driver of investment in renewable capacity

in Spain. Spain is expected to source 20% of its total energy from renewable by 2020 and

Portugal 31% (from 8.7% and 20.5% respectively in 2006).

The Spanish electricity system has seen substantial growth in renewables, with Solar PV

having added 3.3GW to the system in the last three years. This has contributed to a large

increase in total system costs, which in turn has increased the Spanish tariff deficit. As a

result, the Spanish government has instituted a pre-registry for new renewable projects,

which will determine which renewable projects are developed until 2012. EGP had

Year to December 2008 2009 2010E 2011E 2012E 2013E 2014EMWItaly, Capacity

Hydro 1,510 1,509 1,510 1,511 1,513 1,523 1,533Geothermal 671 695 711 728 728 728 743Wind 362 429 503 557 697 847 977Solar 4 4 36 76 106 136 166Other 0 0 0 0 0 0 0Total 2,547 2,637 2,760 2,872 3,044 3,234 3,419Net additions 56 90 123 112 172 190 185GWhItaly, Production

Hydro 5,235 6,231 6,017 6,021 6,027 6,050 6,090Geothermal 5,181 5,000 5,050 5,357 5,612 5,612 5,670Wind 467 499 735 836 1,043 1,285 1,518Solar 2 2 26 74 120 159 198Other 0 0 0 0 0 0 0Total 10,885 11,732 11,828 12,287 12,802 13,106 13,476

growth (%) 8.4% 7.8% 0.8% 3.9% 4.2% 2.4% 2.8%

21,900

29,400

1,900

3,800

1,800

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Wind Small hydro Solar Other Total

MW

1,190

2,561

1,189

21

0

500

1,000

1,500

2,000

2,500

3,000

Iberia 2009PF Wind Solar Iberia 2014

MW

other 161



583MW in the “preregistro” as of 1H 2010. Furthermore, EGP has a 30% holding in ENEOP,

a wind company in Portugal, which is in the process of building 1,200MW of wind farms.

EGP will fully consolidate its 30% holding in 2013 (currently an associate), thus adding

360MW to its consolidated installed capacity.

Two regimes for wind remuneration in Spain

The Spanish wind farm remuneration regime (RD 661/2007) uses market power prices

with a premium (currently €31.0/MWh) and a cap and floor of €89.6/MWh and €75.4/MWh

respectively (see Exhibit 111 in the appendix for details of all relevant regulation; wind

farms brought on line before 2008 will be remunerated under RD 436 which gives a

premium of €38.3/MWh on top of the power price). There is also an alternative option,

choosing a fixed remuneration for 20 years (currently €77.5/MWh). We expect all new

wind farms to be built in Iberia to be incentivized.

At year end 2010, the Spanish government approved regulatory changes to the RD661

wind regime. The government will reduce the €31/MWh premium to €20.1/MWh for 2011

and 2012 (although keeping the floor for compensation at €75.4/MWh). The premium is

then set to return to €31 in 2013. We include these changes in our estimates.

Exhibit 67: EGP Iberian installed capacity and production data by technology


Europe (ex. Italy & Iberia): we expect 0.5GW of capacity additions

EGP operates in France, Greece and Romania. With 222 operating MW, this region

represents only 4% of installed capacity (in MW as a percentage of 2009PF; EGP is in the

process of divesting its 21MW wind operations in Bulgaria). We expect the company to

add 505MW (after divesting Bulgaria) to 2014, 15% of its total additions. Europe

represents less than 2% of 2009PF production, with our estimate for 2014 production as

less than 5%. Exhibit 68 shows the split of total renewable installed capacity (ex. large

hydro) by country as of 2009. Exhibit 69 illustrates the additions we expect EGP to make in

France, Greece and Romania.

Year to December 2009 2010E 2011E 2012E 2013E 2014E

MWIberia, Capacity

Hydro 29 57 57 57 57 57Geothermal 0 0 0 0 0 0Wind 439 1,412 1,619 1,769 2,279 2,379Solar 0 13 18 23 28 33Other 26 92 92 92 92 92Total 494 1,574 1,786 1,941 2,456 2,561Net additions 1,080 212 155 515 105

GWhIberia, Production

Hydro 58 197 200 200 200 200Geothermal 0 0 0 0 0 0Wind 766 2,560 3,186 3,561 4,433 5,101Solar 0 17 27 36 45 53Other 143 415 506 506 506 506Total 967 3,189 3,919 4,303 5,183 5,860growth (%) 229.8% 22.9% 9.8% 20.4% 13.1%



Exhibit 68: France, Greece and Romania had an

aggregate 9GW of installed renewable capacity as of

2009... Renewable power capacity for France, Greece and Romania,

ex large hydro (rounded to the nearest 1GW)

Exhibit 69: ... we expect EGP to add 526MW by 2014, with

the vast majority of additions in wind GS expected additions of renewable capacity from 2009-2014


Source: EGP data: Europe 2009PF, Goldman Sachs Research estimates.

France, Greece and Romania also have ambitious renewables targets

France, Greece and Romania are required to derive 23%, 18% and 24% of their energy

from renewables by 2020, from 10%, 6% and 17% respectively in 2006. Remuneration

schemes in France and Greece are through feed-in tariffs, €81-88/MWh for wind and

€276-440/MWh for solar PV, depending on the installation size (although the latter are

likely to be cut to take into account the rapidly falling cost of solar panels). France is

currently reviewing its solar subsidies to reduce the rate of installations.

High incentives in Romania

Romania has an attractive green certificate (GC) and mandatory quota system similar to

that of Italy. Wind producers get two GCs per MWh of wind energy with prices for GCs

capped at €55 and a floor set at €27. GCs are on top of the pool price. This combination of

incentives makes Romania one of the most attractive places to install wind power in

Europe (where peers of EDP Renovaveis are achieving c. €134/MWh). EGP has 34MW

under construction in Romania and 70MW ready to build (as of 1H2010). Notably, the Enel

group has a large presence in Romania, as it also owns three distribution companies,

including the distributor for the capital, Bucharest. Specifically for Romania, the

government targets a rise in electricity from renewables from 8.3% in 2010 to 20% by

2020.

Exhibit 70: EGP European installed capacity and production data by technology


8,000

9,000

1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

France Greece Romania Total

MW

212

748

10

482

935

0

100

200

300

400

500

600

700

800

Europe 2009PF Wind Hydro Solar Europe 2014

MW


MWEurope, Capacity

Hydro 10 10 13 19 19 19Geothermal 0 0 0 0 0 0Wind 212 236 398 494 594 694Solar 0 0 5 15 25 35Other 0 0 0 0 0 0Total 222 246 416 528 638 748Net additions 24 170 112 110 110GWhEurope, Production

Hydro 17 26 30 42 50 50Geothermal 0 0 0 0 0 0Wind 298 451 639 899 1,096 1,298Solar 0 0 3 13 26 39Other 0 0 0 0 0 0Total 315 478 672 954 1,172 1,387

growth (%) 51.6% 40.7% 41.9% 22.9% 18.3%



North America: we expect 0.6GW of capacity additions

North America is EGP’s third largest market in terms of installed capacity (14% in MW as a

percentage of 2009PF), but fourth largest in terms of production, with 12% of 2009PF

output. We expect the company to add 643MW to 2014, 19% of total additions and for

North America to produce 15% of output. Exhibit 71 shows the split of total US renewable

installed capacity (ex. large hydro) as of 2009. Exhibit 72 shows our forecast of EGP’s

additions in North America as a whole.

State targets and federal support for the US

US regulation is currently a patchwork of state-level renewable portfolio standards (where

the state regulator requires a certain percentage of electricity to be generated from

renewables resources) and federal-level production and investment tax incentives. The

combination of RPS and tax incentives generally leads to a purchase power agreement

(PPA) between wind farm operator and larger utilities.

PPAs are also influenced by the prevailing power price, particularly if the state RPS is not

a binding reason for procurement of renewable power. As demand for power in the US

remains constrained by lower economic activity, and power prices remain low as a result

of excess natural gas, PPAs for renewable projects are more difficult to sign. This has led

to a slowdown in the rate of installations for wind farms in particular. The US installed

c.10 GW of wind power in 2009 alone, while available 2010 data indicates a drop of 50% to

c.5 GW.

Exhibit 71: The US is one of the largest single renewable

energy market globally, with 59.8GW of installed

capacity ... Make up of Iberian renewable power generation (hydro is

small hydro)

Exhibit 72: ... we expect EGP to add 623MW by 2014, with

the vast majority of additions in wind GS expected additions of renewable capacity from 2009 to

2014


Source: EGP data: North America 2009PF, Goldman Sachs Research estimates.

We expect Enel Green Power to be able to add capacity in California

EGP is unlikely to be immune to the slowdown in the market and we assume it only

converts a very small fraction of its 8.3GW pipeline in the US.

35,000

59,800

7,000

3,0002,000

13,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Wind Small hydro Geothermal Solar Other Total

MW

406

1,411

314

606

17

0

200

400

600

800

1,000

1,200

1,400

1,600

North America 2009PF Wind Geothermal North America 2014

MW



Exhibit 73: Enel Green Power pipeline in the US


Of the 623MW of additions we forecast, 276MW (as of 1H2010) are either under

construction or ready to build (meaning they are fully permitted with signed PPAs). We

therefore only expect 300MW of new developments in the US, which considering the

large pipeline in the profitable Californian market (where renewable “RPS” incentives

currently reach US$50/MWh) could occur by 2013/14 and 60MW in Canada over the

period.

Exhibit 74: EGP North America installed capacity and production data by technology


Latin America: we expect 0.4GW of capacity additions

Although Latin America represents c.12% of 2009PF capacity, it delivered 17% of output in

2009. This is a result of high load factor hydro plants, particularly Fortuna in Panama. We

CA, Solar and windStrong “in state” demand, attractive prices

• Acquire presence in California market and interconnected states

• Early stage 3,900 MW pipeline

AB, WindLiquid market with good

wind resource~ 300 MW in Alberta Northern Midwest, Wind

Good wind resource, medium prices, RPSs• Expand in Northern Midwest with strong State

RPS, more liquid merchant market (MISO) and long term Demand f rom RPS

• Early stage 4,000 MW pipeline

North East, Wind and SolarLiquid markets and strong RPSs

Southern Midwest, WindVery good wind resource,

medium-low prices

NV, UT, Geothermal and SolarStrong in state demand (NV)

~ 100 MW

Alberta

California

Nevada

Utah

Kansas

Nebraska

S. Dakota

N. Dakota Minnesota

Iowa

Illinois

Wisconsin

MichiganMassachusetts

Year to December 2008 2009 2010E 2011E 2012E 2013E 2014E

MWNorth America, Capacity

Hydro 314 314 314 314 314 314Geothermal 47 47 47 47 47 64Wind 406 406 482 682 782 1,012Solar 0 0 0 0 0 0Other 21 21 21 21 21 21Total 749 788 788 864 1,064 1,164 1,411Net additions 39 0 76 200 100 247

GWhNorth America, Production

Hydro 997 990 990 990 990 990Geothermal 155 272 288 309 329 389Wind 1,127 1,228 1,368 1,806 2,252 2,754Solar 0 0 0 0 0 0Other 149 149 149 149 149 149Total 1,900 2,428 2,639 2,795 3,254 3,721 4,282growth (%) 27.8% 8.7% 5.9% 16.4% 14.4% 15.1%



expect net capacity additions of 367MW by 2014 (10% of the total), with output at 16% of

the total. Latin America had limited wind and solar power installed capacity as of 2009,

although it is a very large hydro market. Exhibit 75 shows the additions we expect EGP to

make in Latin America.

Exhibit 75: We expect EGP to add 367MW between wind, hydro and geothermal plants

GS expected additions of renewable capacity, 2009-2014E

Source: EGP data: Latin America 2009PF, Goldman Sachs Research estimates.

Hydro developments in Costa Rica & Guatemala; geothermal potential in Chile

Several key projects are coming on line in Latin America including two hydro plants, one

in Costa Rica (50MW) and another in Guatemala (85MW). We expect two geothermal

plants to come on line in Chile towards the end of our forecast period. We expect the rest

of capacity growth to be driven by wind projects.

Exhibit 76: EGP Latin American installed capacity and production data by technology


Sensitivity to installation: the risk is to the upside

Our Enel Green Power capacity forecasts fully includes the company’s target to add

3.5GW of new capacity (reaching 9.2GW) by 2014. As explained previously, we are

confident on delivery, given EGP’s significant financial headroom and the large pipeline to

targeted growth relative to peers.

24

1,034

643

190

137

40

0

200

400

600

800

1,000

1,200

Latin America 2009PF

Wind Small hydro Geothermal Latin America

MW


MWLatin America, Capacity

Hydro 643 644 645 730 780 780Geothermal 0 0 0 0 20 40Wind 24 24 24 24 114 214Solar 0 0 0 0 0 0Other 0 0 0 0 0 0Total 667 668 669 754 914 1,034Net additions 1 1 85 160 120GWhLatin America, Production

Hydro 3,386 3,389 3,395 3,495 3,838 3,965Geothermal 0 0 0 0 74 221Wind 75 75 75 75 272 646Solar 0 0 0 0 0 0Other 0 0 0 0 0 0Total 3,461 3,464 3,470 3,570 4,184 4,832growth (%) 0.1% 0.2% 2.9% 17.2% 15.5%



However, as a downside sensitivity, below we analyze a lower growth scenario, where we

assume only 90% of the targeted installation programme to 2014 is achieved (3.15GW

rather 3.5GW). In this scenario, we assume 90% as this is the average capacity rollout vs.

targets we factor into our estimates for green utility peers.

Exhibit 77: Under a lower growth scenario (90% of targeted installations) our EBITDA estimates would be only

marginally lower


Potential to double growth if gearing is taken to level of peers

We have also assessed an upside installation scenario, were EGP gears up its balance

sheet to the level of its peers. We estimate that this would allow it to spend an extra €5 bn

on capex (beyond its targeted €5.2 bn + associates). We estimate that this would take

EGP’s net debt/EBITDA closer to the average of its peers (4.4x net debt/EBITDA by 2014E)

from its current low level, allowing EGP to increase its capacity to 13GW in 2014 and

40TWh of production (vs. 9.2GW and 29TWh respectively), doubling the growth over the

period (>7GW compared to 3.5GW in our forecasts). We estimate that this would add

c.€600 mn of EBITDA in 2014 (to €2.6 bn), from our current estimate of €2 bn.

Risks: regulation, growth, prices and future level of feed in tariffs

The major risks facing Enel Green Power relate to regulation, wholesale power price

evolution and delivery of growth. In Italy, the Italian green certificate system is

being phased out to be replaced with feed-in power tariffs, the level of which is

unknown. Seasonal (not structural) risk could also come from the fluctuations of

hydro and wind conditions and the company bears geothermal exploration risk.

Movements in exchange rates and interest rates also pose a potential risk.

Changes in regulation or tariffs

While Enel Green Power faces potential adverse regulatory development in each of the

countries in which it operates, the three most material regulatory developments affect

Italy, Spain and the US.

Italy: uncertainty over future feed-in tariffs post green certificate system, corporate taxes and fees for hydro concessions

In Italy, we view the major risk as changes to regulation for renewables. A new

remuneration system is being discussed which would (1) introduce a new incentive

system for new renewable plants that come on stream after December 31, 2012,

differentiating between the size of the plant: feed-in tariff for plants smaller than

10MW (no indication on tariffs level at the moment) and an auction system for plants

bigger than 10MW; (2) confirm the obligation for the system operator GSE to buy

green certificates, but at 70% of the issue price determined by the 2008 Budget Law,

i.e. (€180-pool price)*70%; (3) gradually reduce to zero the quota at which thermal

generators are required to input certificates into the system by 2015 (starting from

Low Scenario € mn 2010E 2011E 2012E 2013E 2014E Base case € mn 2010E 2011E 2012E 2013E 2014EEBITDA group 1,317 1,418 1,548 1,741 1,940 EBITDA group 1,317 1,424 1,561 1,773 2,009Net Income 463 446 496 574 655 Net Income 463 445 488 568 661MW 6,036 6,527 7,261 7,976 8,813 MW 6,036 6,607 7,331 8,406 9,173Production 21,597 23,047 24,701 26,788 28,936 Production 21,597 23,144 24,882 27,366 29,838

Low Scenario (%) 2011E 2012E 2013E 2014E CAGR Base case % 2010E 2011E 2012E 2013E 2014EEBITDA growth 8% 9% 12% 11% 10% EBITDA growth 8% 10% 14% 13% 11%NI growth -4% 11% 16% 14% 9% NI growth -4% 10% 16% 16% 9%MW growth 8% 11% 10% 10% 10% MW growth 9% 11% 15% 9% 11%Production growth 7% 7% 8% 8% 8% Production growth 7% 8% 10% 9% 8%



2013); (4) move all renewables to the new feed-in tariff system from 2016. The level of

the new feed-in tariffs will be key for the future profitability of plant and adds

uncertainty going forward. We currently forecast that from 2013, only new investment

wind farms and Solar PV (of relevance to EGP) will receive incentives above the pool

price in Italy (old plants will keep green certificates until year end 2015). Given the

uncertainty surrounding levels of feed-in tariffs, we have modeled that wind farms

will receive €110/MWh (a level which will deliver a 7.5% IRR on our estimates), equal

to that which we forecast for Spain and in line with our WACC assumptions. Under

this scenario, however, new hydro and geothermal investment in Italy continue to

have returns above the cost of capital (IRRs of 9% and 11% respectively), assuming

no subsidies. A change of €10/MWh in the subsidy level for EGP’s Italian generation

(assuming 23% receives subsidies in 2011) has an impact of 2% on 2011E EBITDA. We

estimate EGP’s revenues from green certificates is €214 mn in 2011, 15% of EBITDA.

In 2008, the Italian government introduced an additional 5.5% corporate tax for all

energy companies in Italy. There is no guarantee that the government might not

attempt to introduce a similar additional tax in the future. In 2009, the government

introduced an additional 1% corporate tax for energy companies, which was

overruled by a national court however. In our estimates for other Italian utilities, we

assume that this tax is introduced from 2012 as a form of political intervention. A 1%

higher tax rate for EGP would have a 1.7% negative impact on EPS.

The recent “summer budget” law 122/2010, article 15, granted up to 7-year life

extensions to most hydro concessions, provided that at the end of the concessions

companies allow local government to take a 30%-40% stake. As a result, Enel Green

Power now expects its hydro concessions to last till 2034 (from 2029 previously).

However, the government has also introduced additional fees for hydro concessions

of €7/KW. We estimate this represents a cost €11 mn pa for Enel Green Power

(already implicit in our models). There is no guarantee that in the future such charges

might not be increased.

Spain: New laws approved (wind, solar PV), but long term uncertainty remains

In Spain, the government signed a new law for the wind sector in December. While all

wind farms built before 2008 will be unaffected, new wind farms will see their premia

reduced by 35% for two years (until 2012 inclusive), from €31/MWh to €20/MWh. Pre-

2008 wind farms will continue to receive a €38/MWh premium. From 2013, there will

be no change, with all wind farms moving to the new system with caps and floors

(currently set at €75-87/MWh, adjusted for inflation), or with the option to receive

fixed feed-in tariffs (currently €77.5/MWh). In our estimates for all Spanish wind

farms, we assume that from 2012 they are forced onto feed-in tariffs at the current

level of €77.5/MWh. This is more harsh than the approved law, but given continued

pressures on budgets and the pressure on the Spanish electricity deficit, we do not

rule out future re-regulation of the Spanish wind sector. As of 1H2010, 67% of Enel

Green Power’s installed capacity in Iberia (1,408MW) was under the old regime (i.e.

receiving the €38/MWh premium relative to pool prices for wind), 18% under fixed

tariffs and 6% under the new system with caps and floors. 9% of the capacity was

under PPA (in Portugal).

The Spanish government also announced a retroactive cut to solar PV subsidies of

30% for two years. Enel Green Power España has 12MW of solar in Spain which will

be affected by the cut (a c.€3 mn EBITDA impact).

US federal renewable energy support remains uncertain beyond 2011

In the US, the support for renewable energy is uncertain post 2011 for wind, as the

current federal support system (in the form of production or investment tax credits) is

expected to expire in 2012. A cash grant in lieu of these tax incentives for wind is being

extended until the end of 2011.



In addition to federal support, 29 individual US states also have mandatory renewable

quotas (“RPS”, or renewable portfolio standards). Given the current targets, the growth in

renewable production and the fall in overall demand in 2010, several states have already

reached or exceeded their RPS targets and given current quotas might not need any

further renewables to 2015 or even 2020.

Exhibit 78: Enel Green Power’s US exposure, by state and technology


Failure of adequate incentives could jeopardize growth targets

To hit its growth targets and maintain high profitability, we believe Enel Green Power will

continue to rely on subsidies or incentives for its renewable production, as the

technologies are today not competitive with traditional thermal generation.

This could be particularly true in the US, where for example, according to EDP, Texas

(ERCOT), the Midwest area MISO (where Enel has 4,000MW of early stage pipeline) might

not require any additional renewables as it has already reached its RPS quotas. In the

absence of adequate state or further federal support, the profitability of such projects

might not be economically viable and therefore the pipeline may never be developed.

The exception to these appears to be California, where the state has set itself a target of

33% of electricity from renewables by 2020. Enel has around 4,000MW of early stage

pipeline in California.

In Europe, the European Union has set to all its member states a binding target to derive

20% of their energy from renewable sources by 2020, compared to the current level of

only c.10%. While policy might vary across different countries, nonetheless the

continent-wide long-term binding national quotas provide better visibility and a

significant potential requirement for growth in renewables. As such, failure to grow in

these markets would be mostly down to Enel Green Power’s inability to deliver new

installations.

North AmericaHydro 314Wind 406Geothermal 47Biomass 21Total 788

USHydro 314Wind 379Geothermal 47Total 740

CanadaWind 27Biomass 21Total 48

Hydropower

Geothermal

Wind Power

Bio mass

Geothermal & Hydropower

Hydropower & wind

CANV

UT

ID

WA

ABQC

NL

NY

MEVT

NHMA

CTPA

WV

NCSC

GA

VAKS

MN

TX



Lower power prices would negatively impact Enel Green Power

As discussed previously, Enel Green Power is greatly exposed to higher (or lower) power

prices. To mitigate such exposure, Enel Green Power actively hedges most of its output

(but is unable to hedge 100% of its output as a result of the volatility of its output).

Position in Iberia mostly unhedged

Iberia appears as the least hedged region. This is because most of the wind under the old

regime (receiving pool + €38/MWh of premium) has been left unhedged. The high hedged

price is partly a result of the inclusion of some PPAs in Portugal (with high PPA prices of

c.€120/MWh), and partly the result of the inclusion of some non-wind technologies which

receive higher prices. To reflect potential regulatory risk, post 2012 we assume all wind

goes to fixed feed-in tariffs at €77.5/MWh.

We prefer to be slightly conservative for 2011 in Iberia

For 2011, we assume wholesale power prices for Iberia of €42/MWh respectively, in line

with our assumptions for other Spanish renewables. The current spot price is €40-

50/MWh, while 2011 forwards trade around €49/MWh, indicating some potential upside

for the Spanish business. During 1H2010, however, on the back of strong hydro (also

good wind conditions), Spanish day-ahead power price averaged only €30/MWh.

Seasonal risk for hydro and wind production

Hydro and wind suffer seasonality. This implies quarterly production data could be

volatile, affecting volumes. While wind volatility typically does not last more than two or

three quarters, hydro volatility (drought or floods) could last several years, as seen in

historical production data for Italy. El Niño, which tends to occur at regular multi-year

intervals, could also have adverse effects on hydro production in some Latam countries.

Exhibit 79: Italian hydro production dropped sharply between 2001 and 2007, but has

recovered recently

Italian hydro production and hydro coefficient (1= average, <1 dry, >1 wet year)

Source: Terna.

20.6

20.7

20.7

20.8

21.0

21.1

21.3

21.4

21.5

21.6

21.7

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

1.2

0

10

20

30

40

50

60

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Hyd

ro c

oef

fici

ent

GW

(ca

pac

ity),

TW

h (g

ener

atio

n)

Hydro installed capacity Hydro generation Hydro coefficient



Exploration risk in geothermal

The geothermal business presents high exploration risk, as wells are drilled in the ground

to ascertain the potential for resources of geothermal energy. Exploration is currently

under way in Italy, the US, Chile and Nicaragua, which may or may not lead to successful

discovery of geothermal potential. Rare, but not impossible seismic movements could

also jeopardize existing facilities’ installations and require new drilling, with additional

costs.

FX and interest rate risk

As of 9M2010, 73% of Enel Green Power’s debt was linked to floating rates. In 9M2010,

the average cost of debt was only 2.8%. A rise in interest rates could therefore lead to

higher interest expense. While as of 9M2010 Enel Green Power had €1.5 bn of short-term

debt (within 12 months), we do not view this as a concern as only a small part (€0.2 bn in

1H2010) of this debt was with third-parties (the majority was with Enel, its parent

company, with which the company has a €2.5 bn 7.5-year credit facility). Additionally, we

expect Enel Green Power to be FCF neutral, therefore not requiring further material

funding, and would expect its parent company to support it in case of exceptional

liquidity concerns.

While Enel Green Power’s North and Latin American revenues are mostly US

dollar-denominated, its P&L has some FX risk. Enel Green Power does not hedge its US

dollar exposure in the P&L. A 10% movement in the euro versus the US dollar would have

a €22-24 mn impact on 2010E EBITDA as a translation effect. A stronger US dollar would

typically also result in higher energy commodity prices in euro terms and thus higher

power prices in euro terms. As of 1H2010, 11% of its net debt was denominated in US

dollars.

Financials: double-digit growth rates

Enel Green Power has a stated business plan target, presented by Enel at its FY2010 results: to grow its EBITDA from €1.4 bn in 2011E to €2.1 bn in 2014. In the process,

the company expects to invest €5.2 bn to grow its capacity from 5.7GW to 9.2GW at

the end of the period. We believe the company will be able to fund most of its growth from its cash flow, and that its net debt/EBITDA will fall over this period, to

1.9x. We forecast the company will deliver broadly double-digit growth, with an

11.1% EBITDA CAGR and 9.3% net income CAGR over 2010-2014.

Some major corporate activity in 2010

The acquisition and full consolidation of Endesa’s renewables (ECyR) from 2Q 2010

(April 1) should be the main driver of EBITDA growth at the consolidated level for 2010. In

2010, we also expect Enel Green Power to experience lower financial expense than in

2009, primarily as a result of the capitalization of the €3.7 bn loan by Enel Spa in 1H from

2010.

Achieved power prices to fall in Italy in 2011E (on hedging), then to rise

We also expect achieved prices in Italy in 2011 to fall by €4/MWh (from €76MWh to

€72/MWh; Exhibit 80 shows only the hedged portion for 2010 and 2011) considering the

annual 12TWh of production in Italy, this should have a €50 mn negative impact on the

P&L. From 2012, we expect a small increase in the achieved price (+€1/MWh), followed by

further increases in 2013E and 2014E (+€5/MWh in each year).



Exhibit 80: Except for Iberia, Enel Green Power has hedged most of its output Enel Green Power forward hedging; from 2012 we show our expected achieved prices by

region. Achieved prices in Italy do not include GC or other incentives (c.€15 mn pa from 2011E).

Iberia includes all technologies


CIP6 expiring during 2010 in Italy

In the Italian business, we estimate that the expiry of some CIP6 contracts in 1H 2010 will

have a €45 mn negative yoy impact in 2010, and a further €30 mn negative impact in 2011,

when there will be no CIP6 contribution left. At the end of 2009, Enel Green Power had

five CIP6 contracts (one in geothermal expired in February and the others (hydro) mostly

in June) (see Exhibit 81).

Exhibit 81: Incentivized production at Enel Green Power, by region and technology; lower

incentives in Italy in 1H


Dividend policy at the top end of the renewable companies

Enel Green Power intends to have a dividend payout ratio in line with the top end of its

renewables peers. With most of the renewable companies paying around 30% of their net

income as dividends, we assume Enel Green Power will pay out 30% of its net income as

dividends from 2011.

2010E 2011E 2012GSf 2013GSf 2014GSf

Italy % 82% 81%

Price, €/MWh 78 71 73 78 83

Iberia % 39% 43%

Price, €/MWh 97 100 93 93 94

Latam % 98% 89%

Price, €/MWh 70 70 70 70 70

North America % 90% 82%

Price, €/MWh 41 41 41 42 42

2009 Hydro Geo Wind Average

Italy 14% 34% 99% 26%

Europe 99% 100% 100%

Iberia (pro‐forma) 100% ‐ 100% 100%

Latin America 12% ‐ 0% 12%

North America 8% 54%* 91% 55%

Total 14% 34% 96% 39%

*ITC (cash grant)

1H2010 Hydro Geo Wind Average

Italy 14% 29% 100% 25%

Europe 100% 100% 100%

Iberia 100% ‐ 100% 100%

Latin America 5% ‐ 0% 5%

North America 26% 0% 92% 52%

Total 14% 28% 96% 35%



Exhibit 82: Enel Green Power installed capacity summary, by technology and region

MW

Source: Company data, Enel annual report 2008, 2009, Goldman Sachs Research estimates.

Exhibit 83: Enel Green Power capacity additions summary, by technology and region

MW

Source: Company data, Enel annual report 2008, 2009, Goldman Sachs Research estimates.

Exhibit 84: Enel Green Power production summary, by country and by technology GWh. 1,000 GWh = 1 TWh. Italy and Europe form one division, Iberia and Latin America

another


Some exceptional in 1H2010

In 2010, Enel Green Power enjoyed €25 mn of fiscal benefits (booked in 1H) from the

Tremonti-ter law, which allows for fiscal benefits on reinvestments. This benefit is

currently under dispute. As the dispute could take a long time to settle, we have left the

benefit in Enel Green Power’s 2010 accounts. We assume no further benefit from 2011.


MWCapacity by technology

Hydro 2,498 2,505 2,535 2,540 2,633 2,693 2,703Geothermal 678 742 758 775 775 795 847Wind 1,237 1,510 2,581 3,080 3,666 4,616 5,276Solar 4 4 49 99 144 189 234Other 47 47 113 113 113 113 113Total 4,464 4,808 6,036 6,607 7,331 8,406 9,173

Capacity by region

Italy 2,547 2,637 2,760 2,872 3,044 3,234 3,419Europe 222 246 416 528 638 748Iberia 494 1,574 1,786 1,941 2,456 2,561Latin America 667 668 669 754 914 1,034North America 788 788 864 1,064 1,164 1,411Total 3,296 4,808 6,036 6,607 7,331 8,406 9,173

749

Year to December 2008 2009 2010E 2011E 2012E 2013E 2014EMWNet capacity additions by technology

Hydro 17 6 30 5 93 60 10Geothermal 0 64 16 17 0 20 52Wind 380 273 1,071 499 586 950 660Solar 0 1 45 50 45 45 45Other 0 0 66 0 0 0 0Total 397 344 1,228 571 724 1,075 767

Net capacity additions by region

Italy 56 90 123 112 172 190 185Europe 0 0 24 170 112 110 110Iberia 0 0 1,080 212 155 515 105Latin America 0 0 1 1 85 160 120North America 341 254 0 76 200 100 247Total 397 344 1,228 571 724 1,075 767


GWhProduction by technology

Hydro 9,653 10,689 10,619 10,636 10,754 11,128 11,295

Geothermal 5,218 5,155 5,322 5,646 5,921 6,015 6,280Wind 2,061 2,765 5,049 6,104 7,384 9,338 11,317Solar 2 2 43 104 169 230 291Other 308 292 564 655 655 655 655Total 17,300 18,903 21,597 23,144 24,882 27,366 29,838

growth (%) 9% 14% 7% 8% 10% 9%

Production by region

Italy 10,885 11,732 11,828 12,287 12,802 13,106 13,476Europe 315 478 672 954 1,172 1,387Iberia 967 3,189 3,919 4,303 5,183 5,860Latin America 3,461 3,464 3,470 3,570 4,184 4,832North America 2,428 2,639 2,795 3,254 3,721 4,282Total 17,300 18,903 21,597 23,144 24,882 27,366 29,838

growth (%) 9% 14% 7% 8% 10% 9%

6,415



In 1H 2010, Enel Green Power experienced exceptional costs in Panama; it had to buy

power to supply its contractual obligations, driven by lower hydro availability due to El

Nino. Such exceptional costs amounted to €25 mn according to the company.

Material associates at Enel Green Power

Equity income contains the share of income from several operating companies and

developers. As some of the associates are development companies (with no assets

currently, but only operating costs), we expect the income from associates to gradually

improve as projects are developed. Associates also include investments in two solar joint

ventures, which could become net income positive from 2012/2013, in our view. We

prudently assume a 5% return on investment from associates, rising to 8% by 2014.

Portuguese associate ENEOP to be fully consolidated in 2013

In 2013, Portuguese associate ENEOP will be split among its shareholders (Enel Green

Power España has 30%). This should lead to 360MW being fully consolidated at Enel

Green Power, as well as €350 mn of debt at the associate coming onto the balance sheet.

Consolidated equity income is likely to fall as this item becomes fully consolidated.



Exhibit 85: 11% EBITDA CAGR for 2010-2014E, 9.3% CAGR for net income. Enel Green Power has stated business plan

targets of €1.4 bn of EBITDA in 2011 and €2.1 bn in 2014 Enel Green Power P&L, cash flow statement and balance sheet (€ mn)

Our estimates only include EGPs Bulgarian assets as held for sale, we make no adjustment for the asset split of EURFER assts between EGP and Gas

Natural Fenosa, as these will return to the balance sheet once the split transaction is completed.


Low cost of debt and financial backing from the parent company

We expect cost of debt, which we forecast at 3.3% for the whole of 2010, to gradually rise,

reaching 5.5% by 2014E. This reflects our expectation of a general recovery in the

European and world economies, in line with the views of our GS economists and GS

commodities analysts. Should this not materialize, our power price forecasts might be too

high, but so too might our financial charge estimates.

Year to December 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E 10-14 CAGR

Profit and loss account 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E 10-14 CAGR

Net revenues 1,776 1,895 2,342 2,490 2,694 2,946 3,187 3,312 8%Operating expenses (635) (688) (1,025) (1,065) (1,133) (1,173) (1,178) (1,175) 4%EBITDA - reported 1,141 1,207 1,317 1,424 1,561 1,773 2,009 2,137 11%EBITDA - adjusted 1,141 1,207 1,317 1,424 1,561 1,773 2,009 2,137 11.1%

Depreciation (418) (416) (511) (563) (611) (660) (706) (751) 8%EBIT 723 791 806 861 950 1,114 1,303 1,386 13%

Associates 0 0 5 19 28 12 15 18 0Net financial expense (228) (133) (108) (126) (157) (187) (213) (202) 19%Profit before tax 495 658 703 755 821 940 1,105 1,202 12%

Gains on disposals/discountinued 0 0 0 0 0 0 0 0Profit before tax 495 658 703 755 821 940 1,105 1,202 12%

Tax (183) (219) (211) (257) (283) (319) (376) (409) 16%Minorities (24) (21) (30) (53) (50) (52) (68) (76) 23%Reported group net income 288 418 463 445 488 568 661 717 9.3%

Exceptionals adjustment, post tax, memo 0 0 0 0 0 0 0 0Clean earnings 288 418 463 445 488 568 661 717 9.3%

Balance sheet 2009 2010E 2011E 2012E 2013E 2014E 2015E 10-14 CAGR

Tangible assets 7,200 9,040 9,536 9,890 10,821 11,192 11,478 5%Investments/intangibles 1,242 2,642 2,711 2,789 2,708 2,723 2,741 1%Fixed assets 8,442 11,682 12,248 12,679 13,529 13,915 14,219 4%

Cash and cash equivalents 372 372 372 372 372 372 372 0%Other current assets 680 831 862 935 1,010 1,081 1,118 7%Total assets 9,494 12,885 13,482 13,986 14,911 15,368 15,709 5%

Current liabilities 890 998 1,033 1,083 1,143 1,201 1,231 5%Other liabilities 267 507 507 507 507 507 507 0%Gross capital employed (including cash) 8,337 11,380 11,942 12,397 13,261 13,660 13,971 5%

Provisions 114 169 169 169 169 169 169 0%Short and long term debt 5,659 3,634 3,827 3,898 4,309 4,171 3,909 4%Shareholders' Equity 2,384 6,819 7,148 7,503 7,924 8,415 8,934 5%Minority interests 180 710 749 779 811 858 911 5%Total liabilities 9,494 12,885 13,482 13,986 14,911 15,368 15,709 5%

Cash flow 2009 2010E 2011E 2012E 2013E 2014E 2015E 10-14 CAGR

EBIT 791 806 861 950 1,114 1,303 1,386 13%Depreciation 416 511 563 611 660 706 751 8%Change in working capital (62) (43) 4 (24) (14) (14) (7) -25%Provision payments, deferred taxes etc 0 0 0 0 0 0 0Dividends received from assoc./JVs 0 0 0 0 0 0 0Interest (79) (108) (126) (157) (187) (213) (202) 19%Tax (219) (211) (257) (283) (319) (376) (409) 16%Operating cash flow 897 875 1,046 1,097 1,253 1,406 1,519 13%

Capex (794) (1,250) (1,110) (1,014) (1,147) (1,076) (1,037) -4%Acquisitions 0 (1,300) 0 0 0 0 0 -100%Divestments / Grants 0 0 0 0 0 0 0Free cash flow (post interest/pre-dividends) 103 (1,675) (64) 83 106 330 482

Dividends 0 0 (129) (153) (167) (192) (221)Financing 0 3,700 0 0 0 0 0 -100%Other, changhes in consolidation (179) 0 0 0 (350) 0 0Change in cash (net debt) at year end (76) 2,025 (193) (71) (411) 138 262Net debt incl. tax/PTC liabilities 5,287 3,262 3,455 3,526 3,937 3,799 3,537 4%



Exhibit 86: Italy to contribute more than 50% of EBITDA through 2014E

Divisional revenues and EBITDA split


Exhibit 87: Around €1 bn of capex per year

Divisional capex split


Year to December 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E

€ mnRevenues

Italy 1,189 1,189 1,168 1,246 1,330 1,429 1,436Europe 32 49 70 101 125 151 177

Italy & Europe 1,144 1,221 1,238 1,238 1,346 1,456 1,579 1,612Iberia 110 288 370 399 479 547 580Latin America 242 242 243 250 293 338 381

Iberia & Latin America 373 352 530 613 649 772 886 961North America 106 144 139 141 161 186 219 257Retail 153 178 435 498 538 532 503 481Other 0 0 0 0 0 0 0 0Total 1,776 1,895 2,342 2,490 2,694 2,946 3,187 3,312Revenues growth (%) 7% 24% 6% 8% 9% 8% 4%Revenue €/MWh 94 91 88 86 87 88 90 88

Year to December 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E€ mnEBITDA

Italy 872 858 836 901 972 1,060 1,062Europe 26 39 56 80 100 120 141

Italy & Europe 838 898 897 892 982 1,073 1,180 1,203Iberia 56 166 244 273 338 402 438Latin America 156 148 171 172 202 246 281

Iberia & Latin America 233 212 314 415 445 540 649 719North America 64 90 72 75 88 114 137 170Retail 6 7 44 42 47 46 43 44Other 0 0 (10) 0 0 0 0 0Total 1,141 1,207 1,317 1,424 1,561 1,773 2,009 2,137EBITDA margin (%) 64% 64% 56% 57% 58% 60% 63% 65%EBITDA margin ex. retail (%) 70% 66.8% 69.4% 70.2% 71.5% 73.3% 73.9%EBITDA growth (%) 6% 9% 8% 10% 14% 13% 6%

Year to December 2009 2010E 2011E 2012E 2013E 2014E 2015E

€ mnDivisional Capex

Italy & Europe (453) (558) (457) (398) (471) (426) (400)Iberia & Latin America (254) (406) (374) (428) (410) (382) (405)North America (36) (87) (228) (139) (266) (269) (232)Retail 0 0 0 0 0 0 0Other (Financial) (50) (200) (50) (50) 0 0 0Total (794) (1,250) (1,110) (1,014) (1,147) (1,076) (1,037)Capex growth (%) 58% -11% -9% 13% -6% -4%

Capex by technology

Hydro (128) (30) (172) (139) (81) (47) (48)Geothermal (199) (120) (60) (89) (172) (222) (230)Wind (408) (760) (742) (671) (824) (743) (696)Solar (139) (85) (64) (69) (63) (61)Other (9) (1) (1) (1) (1) (1) (1)Other (Financial) (50) (200) (50) (50) 0 0 0Total (794) (1,250) (1,110) (1,014) (1,147) (1,076) (1,037)Capex growth (%) 57% -11% -9% 13% -6% -4%

January 19, 2011

Goldman Sachs Global Investment Research

Company and managem

Historica

ENEL Green

separate en

assets, inclu

On January

and the ren

In March 20

(ECyR), the

a capital inc

subscribed

Union Feno

Power Espa

Endesa mai

the acquisit

previously b

Power and

core compe

JV EUFER, w

Exhibit 88: Enel Green Power (EGP) Espan

renewable assets End-2009 data

Source: Enel FY2009 results presentation, Endesa 1H re

ment profile

al development: formed in 2008, built up

n Power is a subsidiary of ENEL Spa. The business was

ntity within the ENEL Group in 2008 with ownership of

uding all geothermal plants, virtually all run-of river hy

y 1, 2009, it acquired ENEL’s international renewable as

ewables equipment retailing company Enel.Si.

010, Enel Green Power acquired 30% of Endesa Cogene

renewables subsidiary in Iberia of Endesa, SA, for €32

crease that allowed it to reach 60% of ECyR. The capita

to with €534 mn in cash and for €280 mn in kind (cont

osa Renovables (EUFER), valued at €280 mn). ECyR wa

ana. Enel Spa owns 92% of Endesa, SA.

intains its Latin American renewables; according to En

tion of exclusive control of Endesa (via the buyout of th

by Acciona), greater coordination has been achieved b

Endesa over Latam renewables projects, with each com

etences. In July 2010, Enel and Gas Natural Fenosa agr

which as of 1H2010 was still proportionally consolidate

na is the result of the combination of ECyR (Endesa) a

esults press release, Goldman Sachs Research estimates.

Enel Green Power (EGPW.MI)

55

in 2009 and 2010

s established as a

ENEL’s Italian renewable

ydro, and all wind assets.

ssets (excluding Endesa)

eracion y Renovables

26 mn and subscribed to

al increase was

ributing 50% of Enel

s renamed Enel Green

el’s management, since

he 25% stake held

between Enel Green

mpany building on its

reed to split their 50-50

ed.

and 50% of EUFER (Enel)



Presence in 16 countries worldwide: Europe, Latam, North

America

Enel Green Power is present in 16 countries: In Europe it is present in Italy, Spain,

Portugal, Greece, France, Romania and Bulgaria. Enel Green Power has put its Bulgarian

assets up for sale, and classified them as for sale as of 1H2010. This coincides with Enel’s

group strategy, to exit non-core countries where the group cannot achieve a vertically

integrated position.

In Latin America, it is present in Panama, Brazil, Mexico, Chile, Costa Rica and Guatemala,

where it owns hydro or minihydro plants. In Costa Rica it also owns a 24MW wind farm

and had recently won a tender to build 90MW of wind farms in Brazil. Enel Green Power

also has a 36.2% minority stake in La Geo SA de CV, a geothermal producer in which it is

trying to achieve majority control (currently in arbitration), and is also prospecting for

geothermal opportunities in Chile, Nicaragua and the US.

In North America, Enel has assets in the US (hydro, wind and geothermal; the major asset

about to start construction is a 200MW wind farm) and Canada (wind and biomass, with a

new 76MW wind farm currently under construction).

Enel Green Power is also pursuing wind, geothermal and solar project opportunities in

Turkey, Morocco, Egypt, Tunisia and South Africa, which we have not taken into account.

Relationship with ENEL Group

Enel plans to achieve €10 bn of cumulative disposals in 2009 and 2010. As of 9M2010,

Enel has closed disposals worth €8.4 bn.

We expect Enel Green Power will continue to benefit from ENEL Group’s scale in

procurement for non-generation equipment.

Experienced management with strong engineering background

Enel Green Power’s management has significant experience of the power generation

sector, both within Enel and elsewhere.

The Chairman is Luigi Ferraris, with a degree in Economics and has been with Enel

since 1999. He is currently CFO of Enel Group, while the CEO, Francesco Starace is the

former head of Enel Produzione (Enel’s Italian power generation arm). Mr. Starace, a

nuclear engineer, had experience in the electrical generation industry (having worked

abroad at GE, ABB, Alstom) before moving to Enel. The CFO, Alberto de Paoli, has a

degree in Economics, and has spent most of his career at Wind, previously Enel’s telecom

subsidiary. He has been with Enel since 2008.

Other key managers in our view are Ingmar Wilhelm, from Essen, Germany, with a degree

in electrical engineering (specialized in Energy Economics) and experience at other large

European utilities. He joined Enel in 2003 to head business development; Vittorio

Vagliasindi, a nuclear engineer heading Engineering & Construction (with Enel since 1980),

and Dino Marcozzi, a nuclear engineer and head of procurement, who has been with Enel

since 1980. Together with Mr Starace, who serves also as interim chief of operation and

maintenance, they form a committee responsible for approving the go-ahead to all new

renewable projects for Enel Green Power.



Appendix 1: Italian generation market and EU power demand

Older plants can adequately supply peaks through the coming decade

Older gas plants which have now moved to mid-merit or peak include Enel’s large

Montalto di Castro plant in Central Italy (3.6GW) and the old Edison CIP6 CCGT plants

(2.2GW). As these are not new CCGTs, Italian peak prices tend to be higher, leading to

higher average base-load prices. As the last 5,000MW of demand in Italy is typically

utilized less than 10% of the time, it is unlikely that companies will try to build new

capacity in the short term to replace this capacity, as it would achieve only very low load

factors. As a result, this has a small positive impact on Italian power prices of €2-4MWh,

we estimate.

As per Exhibit 89, during peak-time (midday or early evening), Italian power demand rises

as do power prices, as less efficient plants come into operation. Enel Green Power can sell

its power throughout the day.

Exhibit 89: A typical day in the Italian day-ahead market

Line (left axis) represents power prices; columns (right axis) demand during the day


New interconnectors might replace old fuel oil as more capacity needed post 2015

While from 2015 Italy might require new capacity, particularly as old fuel oil plants are

unlikely to be compliant with the new large combustion plant directive (LCPD), this might

come in the form of new interconnectors which are currently being planned by Terna with

several countries (including France, Switzerland, Albania, Tunisia and Montenegro for a

total of 6.6GW). According to the system operator, the first interconnectors could be ready

in 2016/2018.

Sicily (and Sardinia) contribute to higher average national wholesale prices

Italy has a national wholesale power price, however the islands, Sardinia and Sicily,

currently each have power prices above the national average. The two islands combined

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

0

20

40

60

80

100

120

140

160

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

hEU

R p

er M

Wh

Hours

CCGT variable costs (fuel, GC and CO2)

Imports, coal and CCGTs up to 8GW of CIP6 havepriority dispatching

Peaking units, including peaking hydro, turbogas

and fuel‐oil plants

Coal variable costs including CO2 and GC

Fuel oil or peakinggas plants

CCGTs in operation



contribute 10% of national demand (Sicily 6% and Sardinia 4%). During 2009, their zonal

power price average was c.€30/MWh, €3/MWh above the national average as a result of

the local generation mix and bottlenecks in transmission. These are being partly resolved

by Terna, which is completing a 1,000MW new interconnector for Sardinia (SAPEI, half

already operational, due to be completed in 2011) and has started a 2,000MW

interconnector to Sicily which is likely to be ready no sooner than 2015 (Sorgente-

Rizziconi). Once completed, these are likely to lead to a substantial reduction in the price

differential.

Large capacity additions since 2002, some in construction

Exhibit 90: Currently 2.4GW in construction; more projects available, but stalled

Amount of new thermal plants built over the last decade or currently being built/planned


Investments over the last five years, particularly in new high-efficiency CCGTs, have

reduced the weight of fuel oil in the mix (from 14% to just 5%), however as most of the

gas in Italy is imported via oil-linked formulas, this has not substantially modified the

Italian generation mix exposure to oil or Brent prices (as oil and gas continues to account

for around 50% of the total generation).

Date first start-up Location Company Size, MW

2002 9602003 4,0302004 6,7502005 5,7602006 3,2002007 5,3102008 3,7602009 2,400

Commercial operation 2010 Scandale, Calabria Eon-A2A 800 Gas CCGTCommercial operation 2010 Nuce, Priolo Gargallo, Sicilia ERG 480 Gas CCGTCommercial operation 2010 Civitavecchia Enel 2,000 CoalTesting (2010) Modugno, Bari, Puglia Sorgenia 800 Gas CCGTTesting (2010) Ferrara ENI-EGL 780 Gas CCGT/CHPEntered into operation last 12 months 4,860

2011 Aprilia, Lazio Sorgenia 800 Gas CCGT2011 Lodi, Lombardia Sorgenia 800 Gas CCGT2011 San Severo, Puglia EnPlus 400 Gas CCGT2012 Torino Nord Iride 400 Gas CCGT/CHPDue to enter into operation over next two years 2,400

Planned but not started2011-12 - we expect it to go ahead Gas peakers Edison 120 Gas SCGT repowering2012 - we expect it to go ahead Turbigo Edipower 400 Gas CCGT repowering2011 ? Ostiglia Eon 400 Gas CCGT repowering2012+ (delay announced) Monfalcone, Friuli A2A 800 Gas CCGT repowering2012+ Tavazzano Eon 400 Gas CCGT repowering2013 - we expect it to go ahead Taranto Eni 140 Gas CCGT repoweringTotal 1,740

Other major projects? Salerno EGL 800 Gas CCGT2015+? Porto Tolle Enel 2,000 Coal2015+? San Filippo del Mela Edipower 1000-2000 Gas/Coal?Withdrawn from business plan Central Italy Edison 800 Gas CCGT



Exhibit 91: Installed capacity, production and demand in the Italian power market

To reach available capacity, installed capacity needs to be multiplied by the technology available

Source: Goldman Sachs Research estimates based on Terna and Company data.

Exhibit 92: Italian generation mix has changed little over the last five years, with gas

replacing fuel oil on the margin Italian gross power generation and imports in 2004, TWh (total value 348 TWh)


Italian Cumulative Capacity (gross MW) 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EHydro 20,658 20,744 20,837 20,987 21,072 21,139 21,429 21,476 21,640 21,738 21,847 21,956 22,066 22,176 22,287 22,398Wind and solar 370 670 787 881 1,138 1,645 1,915 2,801 3,969 6,040 8,040 9,540 11,040 12,040 13,040 14,040

Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Geothermal 626 573 707 707 707 711 711 711 711 737 737 737 737 737 737 737Coal 7,800 7,800 7,800 7,800 7,800 7,940 7,940 7,940 7,940 8,600 9,920 9,920 9,920 9,920 9,920 9,920CCGT 4,750 6,470 7,430 11,460 18,210 23,970 27,170 32,480 36,240 37,840 40,740 42,740 43,140 43,340 43,340 43,340Gas (simple cycle or peaker) 28,082 26,804 27,227 25,098 21,879 19,323 17,723 15,068 13,188 12,388 10,938 9,938 9,738 9,638 9,638 9,638Fuel oil 15,799 15,726 14,539 13,617 13,617 13,617 12,117 10,617 10,617 10,617 10,617 10,617 10,617 10,617 10,617 5,617Interconnectors 5,700 5,700 5,700 6,000 6,000 6,000 7,000 8,000 8,000 8,000 8,000 8,200 8,400 8,600 8,800 9,000Total (MW) 78,085 78,787 79,327 80,550 84,423 88,345 89,005 91,093 94,305 97,960 102,839 105,448 107,258 108,468 109,579 105,690Maximum available capacity (Terna) 70,009

Italian power production, TWh 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015EHydro production 51 54 47 44 50 43 43 38 47 53 48 48 49 49 49 49Gross thermal production 220 219 231 243 246 253 262 266 261 227 239 244 248 252 256 261Gross geothermal production 5 5 5 5 5 5 6 6 6 5 5 5 6 6 6 6Wind and solar 1 1 1 1 2 2 3 4 5 7 10 12 15 17 19 22Use from auxilary services -13 -13 -14 -14 -13 -13 -13 -13 -12 -12 -12 -12 -12 -12 -12 -12Sum net domestic production, Twh 263 266 271 280 290 291 301 301 308 282 290 298 305 312 319 326y-o-y change 1.0% 1.8% 3.5% 3.5% 0.2% 3.7% -0.1% 2.1% -8.4% 2.9% 2.9% 2.2% 2.2% 2.2% 2.2%Net Imports 44 48 51 51 46 49 45 46 40 44 42 40 40 40 40 40National demand (net production + imports) 308 314 321 331 336 340 346 348 347 326 332 338 345 352 359 366y-o-y 2.2% 2.3% 3.0% 1.4% 1.2% 1.9% 0.4% -0.1% -6.1% 1.7% 2.0% 2.0% 2.0% 2.0% 2.0%

Peak demand, MW 49,019 51,980 52,590 53,403 54,738 56,107 55,539 56,810 55,292 51,873 56,425 57,836 59,282 60,764 62,283 63,840y-o-y 6.0% 1.2% 1.5% 2.5% 2.5% -1.0% 2.3% -2.7% -6.2% 8.8% 2.5% 2.5% 2.5% 2.5% 2.5%

Hydro

14%

Other

renewables

2%

Imports

13%

Coal

13%

Other fuels

7%

Gas

37%

Oil

14%



Appendix 2: Enel Green Power pipeline

Exhibit 93: Enel Green Power pipeline by geography and technology

MW


Italy Europe Iberia Latam

North

America

New

Markets Total

Wind 2,356 2,529 9,711 4,018 8,207 ‐ 26,821

Solar 652 109 692 33 150 1,636

Hydro 47 5 243 486 ‐ ‐ 781

Geothermal 48 ‐ ‐ 389 100 ‐ 537

Biomass 15 ‐ 53 ‐ ‐ ‐ 68

Other ‐ 12 10 ‐ ‐ ‐ 22

3,118 2,655 10,709 4,893 8,340 150 29,865



Reg AC

I, Mariano Alarco, hereby certify that all of the views expressed in this report accurately reflect my personal views about the subject company or

companies and its or their securities. I also certify that no part of my compensation was, is or will be, directly or indirectly, related to the specific

recommendations or views expressed in this report.

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Disclosures

Coverage group(s) of stocks by primary analyst(s)

Mariano Alarco: Europe-Utilities. Deborah Wilkens: Europe-Utilities. Andrew Mead: Europe-Utilities. Fred Barasi: Europe-Utilities.

Europe-Utilities: A2a SPA, Acciona SA, Centrica, CEZ, Drax Group Plc, E.ON, EDF, EDF Energies Nouvelles S.A., Edison SpA, EDP Renovaveis SA,

Enagas, Endesa SA, Enel Green Power, Enel SpA, Energias de Portugal, Fortum, Gas Natural, GDF SUEZ, Iberdrola Renovables SA, Iberdrola SA,

International Power, National Grid, Northumbrian Water Group, Pennon, PGE, Public Power Corporation SA, Red Electrica de Espana, RWE,

Scottish and Southern Energy, Severn Trent, Shanks Group, Snam Rete Gas SpA, Suez Environnement, Terna, United Utilities, Veolia

Environnement, Verbund.

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Goldman Sachs expects to receive or intends to seek compensation for investment banking services in the next 3 months: Enel Green Power (€1.61)

Goldman Sachs has received compensation for non-investment banking services during the past 12 months: Enel Green Power (€1.61)

Goldman Sachs had an investment banking services client relationship during the past 12 months with: Enel Green Power (€1.61)

Goldman Sachs had a non-investment banking securities-related services client relationship during the past 12 months with: Enel Green Power

(€1.61)

Goldman Sachs had a non-securities services client relationship during the past 12 months with: Enel Green Power (€1.61)

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