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EMEA – POLICY – RESEARCH NOTE
11 February 2015
Contents
1. BACKGROUND ................2
2. STRONG WINDS
DESPITE THE CUT ...........3
3. PV STILL SUNNY FOR
INVESTORS ......................4
4. ARE YOU SERVICING
YOUR DEBT? ...................6
5. A MARKETPLACE FOR
CASH COWS? ..................7
6. PROSPECTS FOR NEW
PROJECTS .......................8
7. IMPACT OF SNAP
ELECTIONS ......................9
APPENDICES .......................11
Greek life under retroactivity: distress or
delight?
In recent years, struggling governments in Europe have implemented retroactive
subsidy cuts for existing renewable power projects, severely affecting investor
confidence. This note on Greece is the first part of a series assessing the impact of
retroactive measures on project profitability, and analysing distressed asset
opportunities in the secondary markets.
•
In 2014, the Greek government implemented permanent retroactive cuts to close an energyrelated budget deficit and catch up with a drastic fall in solar panel costs and an underestimation
of wind speeds. It reduced tariffs by 30% on average for existing PV projects and 5.5% for wind
projects. The measures also included a one-time levy on 2013 income.
•
Despite the cuts, there are no signs of distress for Greek wind farms. A typical mainland project
installed in 2011 should still make sound profits, with post-cut equity internal rate of returns (IRRs)
of between 9% and 18%, according to Bloomberg New Energy Finance analysis. There is still a
market for new wind projects, although all decent islands locations are now occupied. New
mainland projects can expect to earn 10-15% IRRs under the current tariffs.
•
For existing solar projects, conditions are even brighter, making them the cash cows of the Greek
renewables industry. Island projects still earn a whopping 20-30% return, depending on the
connection year and the level of support. IRRs for existing 2011 mainland projects lie in the 1316% range. However, with the latest subsidy change, which links tariffs to the average Greek
power price of the previous year, the prospects for new solar projects are grim.
•
In general, operational wind and PV projects in Greece should have been able to weather out the
tariff reductions without facing difficulties to service their short-term debt obligations. However, the
one-time levy on 2013 income could have put some small-scale PV project owners into distress, if
they were subject to debt covenants without an option to "sculpt", or vary, payments.
•
Private equity funds scavenging the sector for distressed assets may have been disappointed at
the lack of opportunities, but there is still growing interest in the secondary market. Investors are
likely to try to buy up profitable assets and pool them into 50-100MW portfolios in order to seek
refinancing, which could turn out to be difficult, given the current state of commercial banks in
Greece. Our estimates suggest that the average buy-out values should lie in the EUR 1.5-2m/MW
range for wind projects and EUR 1.75-2.5m/MW for PV projects.
•
Janis Hoberg
+44 (0) 20-3525-8303
[email protected]
© Bloomberg Finance L.P.2015
The recent elections have brought even more uncertainty to the economically unstable Greek
market. The new left-wing government has a fairly strong green agenda, but has also pledged to
end the era of austerity and to rewrite its relationship with the rest of Europe. The announced
cancellation of privatisation plans for the energy sector marks therefore just the beginning of a
time for change that could have profound impacts on the industry in the medium term.
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displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
1. BACKGROUND
1.1. Policy recap
Of all Southern European countries facing fiscal problems since the dawn of the financial crisis,
Greece was hit the hardest. The country that had aimed to become a “solar powerhouse” was on the
edge of bankruptcy, prevented only by an unprecedented bailout package worth EUR 110bn from the
“Troika” of the European Union, the European Central Bank and the International Monetary Fund. The
inevitable austerity measures forced the complete overhaul of the country’s public sector and
impacted all sectors of the economy.
Figure 1: Greece
cumulative solar and wind
capacity (MW), 2009-14
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
The high feed-in tariffs introduced in 2006 and augmented in 2010 were based on underestimates of
equipment cost and thus caused a surge in installations (Figure 1). But political uncertainty has not
spared the renewables sector in recent years (Figure 2). The government also provided investment
incentives, contributing 20-40% to investment costs through grants or tax exemptions.
As the crisis hit, the government realised that it had over-subsidised the sector and was ahead of the
trajectory for its 2020 target. It decided to cancel the investment support for new solar projects. In
addition, feed-in tariffs for new projects were cut and incentives for wind projects were limited to tax
exemptions. In November 2012, tariffs for PV projects were cut retroactively for two years1.
Figure 2: Main support changes for old and new Greek renewable energy projects since 2004
2009 2010 2011 2012 2013 2014
Solar Wind
Source: Bloomberg New Energy
Finance.
Law 3299/2004
Law 3468/2006
Law 3851/2010
Law 4027/2012
Law 4093/2012
Law 4254/2014
Law outlines
general investment
incentives for
Greek industry. 2040% contribution to
capital
expenditures for
renewable energy
projects.
Feed-in tariffs
(FiT) for wind,
small hydro, solar,
geothermal and
biomass were first
introduced in
Greece, taken
effect on 1
January 2007.
FiTs for new
projects were
adjusted to
“accelerate the
development of
RE” and
authorisation
procedure for
solar PV simplified
FiTs for new
projects were cut,
as the country
faced budgetary
problems and had
overshot its
intermediate 2012
target towards the
EU 2020 target.
FiTs for solar PV
projects
connected before
the publication
date were cut
retroactively by
25-30% for two
years until June
2014.
FiTs were cut both
retroactively for
existing projects
and pro-actively
for new projects
mainly to adjust
for previous
miscalculation of
equipment costs.
2004
…
2006
…
2010
2011
2012
2013
2014
Source: Bloomberg New Energy Finance.
1.2. The permanent retroactive measure
On 30 March 2014, the Greek Parliament approved the implementation of Law 4254/2014, which was
the first time it cut the tariffs permanently for existing projects. On average, existing PV plants suffered
a 30% reduction in tariff, depending on the connection date and location of the individual power plant.
Existing wind projects were hit less, with a 5.5% average FiT decrease. The government also
imposed a one-time levy on 2013 revenues to close an energy-related budget. The levy amounted to
34-37.5% for solar PV projects larger than 100kW and 10% on all other renewable energy
technologies. As a means of conciliation, support contracts for existing projects were extended by 5-7
years subject to a tariff aligned with the market price or EUR 90/MWh.
1
© Bloomberg Finance L.P.2015
For more information on the temporary cuts, read our Analyst Reaction Athens passes retroactive
cuts on PV: No Greek tragedy
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displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
2. STRONG WINDS DESPITE THE CUT
With the tariff cuts in 2014, the government aimed to reduce the internal rate of return (IRR) of
existing projects to 12-15%. This section analyses theoretical examples of wind projects connected in
2011, to assess the validity of that statement and to identify the potential for a distressed market. It
also compares the IRRs with those that new projects can expect to reap.
2.1. Assumptions
The 2014 retroactive policy change distinguished between projects that received investment support
(as per Law 3908/2011) and those that did not. Projects without support received a 20% tariff increase
as a compensation, although in practice nearly all projects did get some form of investment support
(20-40% depending on the location of the plant). The investment support for the 2011 projects
generally came as a one-off grant, whereas the 2015 projects only received a lower-rated tax
exemption. For our analysis, we assumed an exemplary 10MW plant connected in 2011 or 2015.
Figure 3: Greece 10-year
government bond yields
40
35
30
25
20
15
10
5
0
2010 2011 2012 2013 2014 2015
Source: Bloomberg Terminal.
Our example project is 65% debt-financed with a debt spread of 450 basis points and a loan tenor of
12 years. Projects connected in 2011 managed to avoid the height of the Greek debt crisis as
illustrated by the change in 10-year government bond yields shown in Figure 3. These projects
therefore still received reasonable terms from commercial banks (similar to those offered today), if
they agreed on them before the start of construction (in 2008-09).
Assumptions for capital expenditures (capex) differ by connection date and location (see Table 1). We
assumed a capacity factor of 25.68% for mainland projects and 28.54% for island projects2. The onetime levy of 10% on 2013 income was modelled as an after-tax operating expense.
Table 1: Capex assumptions for wind projects by connection date and geography (EUR/MW)
Date
Mainland
Islands
2011
1,550,000
1,658,500
2015
1,300,000
1,391,000
Source: Bloomberg New Energy Finance.
2.2. Results
Our analysis indicates that wind projects connected in February 2011 are still very much profitable
now, with equity IRRs post-subsidy cuts ranging from 9% to 24%, depending on the level of
governmental support (see Figure 4). Projects located on islands seem to outperform their mainland
neighbours, benefiting from higher FiTs and capacity factors.
In theory, projects that did not benefit from investment incentives received a 20% tariff increase
resulting in higher IRRs (the green bars), though in practice nearly every project did receive a certain
level of support, with an average of 30%. The maximum level of support was only given to projects in
the most underdeveloped areas of the country. We can therefore assume that the average equity
return for a 65%-geared project (post-subsidy cut) should be around 19% for island projects and
about 14% for mainland projects, which falls roughly in line with what the government aimed for.
2
© Bloomberg Finance L.P.2015
These capacity factors represent the load factor limit for the support extension period as outlined in
subparagraph II.4 of Law 4254/2014, broadly corresponding with the five-year load factor average
of 2,225MWh/MW.
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
Figure 4: Greek wind IRRs (%) before and after policy change for a project connected in 2011
There are no signs of
distress in the Greek
wind market.
28
26
24
22
20
18
16
14
12
10
8
6
4
2
0
25.6
23.6
18.7
10.5
17.7
16.2
14.3
Equity
hurdle rate
10.9
10.2
13.6
9.2
6.2
Islands
Mainland
Islands
Mainland
Islands
Mainland
Higher FiT (post-change) Maximum investment support Minimum investment support
Source: Bloomberg New Energy Finance; Notes: The arrows show the change in IRR after the 2014 retroactive
subsidy cuts. Maximum support equates to 40% of investment cost, minimum support to 20%.
The sensitivity analysis (see Figure 13 in the Appendix) shows that besides the tariff, the capex
assumptions and the debt/equity share have the highest impact on the equity IRR. Most existing
projects on islands and on the mainland benefit not only from sound tariffs and invest incentives, but
also from locations with good wind speeds.
The conclusion is that there is no sign of distressed wind assets. This will come as a disappointment
to private equity funds that have been scavenging the market for projects available at a discount due
to financial distress caused by the reduced tariffs. In fact, the seven-year support extension might
possibly further improve the profitability of existing plants, as EUR 90/MWh should easily be enough
to cover operating expenses, with the plant itself fully depreciated after 20 years of operation.
3. PV STILL SUNNY FOR INVESTORS
Table 2: Greek solar
CAPEX assumptions
Year
CAPEX (EUR/MW)
2011
2,750,000
2012
1,700,000
2013
1,400,000
Source: Bloomberg New Energy
Finance.
With the retroactive cuts last year, feed-in tariffs for existing PV projects were slashed by on average
of 33%, and this was coupled with a one-time levy on 2013 revenues. The scale of the measure might
suggest that some developers would not be able to serve their debts and therefore might seek to
either cut costs or sell the asset on the secondary market. Our estimates, however, suggest that the
contrary is the case. We analysed the impact of the cuts by modelling the equity IRRs for a 4MW PV
plant with varying assumptions for connection year, location and support level.
3.1. Assumptions
Tariff cuts for PV projects – unlike those for wind farms – were set on different levels depending on
the connection date (as well location and previous investment support). Consequently, we assessed
the project profitability for different connection dates in 2011, 2012 and 2013. Over the course of
those years solar panel costs declined dramatically as indicated by the capex assumptions (Table 2).
© Bloomberg Finance L.P.2015
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displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
We did not consider potential surcharges by PV system retailers, who might have taken advantage of
the considerable margins for project developers at the time. As per Law 3299/2004, solar projects
were eligible for investment support before 2011. Projects that had received permits prior to the new
legislation (Law 2908/2011) were still eligible for that support. This was the case for a large share of
projects connected in 2011 and 2012 and a few of those connected in 2013.
We assumed capacity factors of 17.12% (for mainland) and 19.41% (for islands)3. Total debt costs
were estimated at 6.4%, with 500bps as debt spread or margin, with a tenor of eight years. As a result
of the financial crisis, debt cost might have been higher in the later connection years, but a sensitivity
analysis (see Figure 14 in the Appendix) shows that changes to the debt costs would only marginally
impact the equity IRRs. The one-time levy on 2013 income was modelled as an after-tax operating
expense in the financial year 2014. The temporary retroactive cut in November 2012 was modelled as
reducing tariffs in financial years 2013 and 2014, until the new bill was approved.
3.2. Results
Existing solar PV plants
are still the cash cows of
the Greek renewables
industry with IRRs of 1330%.
When the government introduced its new tariffs in 2010 to “accelerate renewable energy deployment”,
it underestimated greatly the coming cost reductions in solar panels. This led to windfall profits for PV
project developers until November 2012, when the first retroactive measure took effect. Back then,
project developers were able to lock in their tariffs 18 months before project connection. In that period,
panel costs came down so significantly that the original tariff offered excessive support. This early
misjudgement still benefits projects which, despite the permanent retroactive cuts, are still making
sound returns for their equity investors.
Figure 5: Greek solar IRRs (%) before and after subsidy cuts
for mainland projects connected in 2011/12/13, by support
level
Figure 6: Greek solar IRRs (%) before and after policy change
for island projects connected in 2011/12/13, by support level
60
60
55
55
50
50
45
45
39
40
33
35
30
40
15
25
30
15
16
13
34
26
26
25
18
14
25
26
22
22
20
15
15
10
10
5
5
0
41
36
30
24
18
20
47
35
28
26
58
0
IS
no IS
2011 connection
IS
no IS
2012 connection
IS
no IS
2013 connection
IS
no IS
2011 connection
IS
no IS
2012 connection
IS
no IS
2013 connection
Source: Bloomberg New Energy Finance; Notes: IS= 20% investment support; The arrows show the change in IRR after the retroactive subsidy cuts.
Figure 5 and Figure 6 show the changes in equity IRRs for mainland and island projects before and
after the permanent retroactive cuts in 2014. The graphs distinguish between projects depending on
3
© Bloomberg Finance L.P.2015
These capacity factors represent the load factor limit for the support extension period as outlined in
Law 4254/2014. 2010-2014 average load factors was 1,485-1,725 KWh/KWpeak.
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
the year of connection and whether they received investment support (at 20%). Before the cuts,
mainland projects enjoyed returns of between 18% (for a 2011 project without investment support)
and 39% (2013 project with support). The cuts brought down the IRRs to 13-18%, in line with the
government's aim, but still above our estimated equity hurdle rate of 13% (Figure 5).
This reassuring picture is even more the case for islands projects, earning – in the most extreme
cases – returns of up to a staggering 58% before the cuts. The reductions brought the IRRs down in
to the 22-26% range (Figure 6). Overall, they suffered a substantial decline in revenues as a result of
the cuts, but PV projects in Greece remain cash cows for their owners.
4. ARE YOU SERVICING YOUR DEBT?
Although most wind and solar projects still are still offering strong returns over the course of their
lifetime, some could have hit problems at some point during the disruptive policy changes of the last
few years. The cuts could have put projects at the lower end of the performance range into financial
distress in the face of short-term debt obligations and debt covenants with commercial banks.
We assessed whether the exemplary projects analysed above would be able to meet their annual
debt repayments. The cash flows available for debt service (CFADS) represent the net operating cash
flows less maintenance capex and income tax. The relationship between CFADS and debt service
(interest and principal payments) produces the debt service coverage ratio (DSCR), indicating if in a
given year a project is able to cover its debt.
Figure 7 and Figure 8 show the DSCR of the analysed wind and solar projects for the 2011-16 period
after the subsidy cuts. Unsurprisingly given the sound returns, all project types regardless of location,
connection date or support level seemed to be able to cover the short-term debt commitments both
before and after the tariff change. However, the one-time levy on the 2013 income imposed by the
government as part of the austerity measures last year might have caused temporary troubles for
some small-scale solar project owners, as shown by the significant drop of the DSCR in 2014, well
below the critical ratio of 1:1.
Figure 7: DSCR analysis for a 2011 wind project after subsidy
cut by support level, 2011-16
Figure 8: DSCR analysis for a solar project by connection date
and support level, 2011-16
3.0
3.0
2.5
Higher FiT (Is)
2.5
2.0
Higher FiT (Ma)
2.0
2011 FiT (Is)
2011 FiT (Ma)
2011 Inc (Is)
2011 Inc (Ma)
2012 FiT (Is)
Max support (Is)
2012 FiT (Ma)
1.5
1.5
2012 Inc (Is)
Max support (Ma)
1.0
Min support (Is)
1.0
0.5
Min support (Ma)
0.5
0.0
2011
2012 Inc (Ma)
2013 FiT (Is)
2013 FiT (Ma)
2013 Inc (Is)
2012
2013
2014
2015
2016
0.0
2011
2013 Inc (Ma)
2012
2013
2014
2015
2016
Source: Bloomberg New Energy Finance; Note: Ma=Mainland, Is=Island, Inc=with investment incentive
© Bloomberg Finance L.P.2015
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
What that means in practice is largely dependent on the terms agreed between the individual project
owner and the commercial banks providing the debt financing. For instance, if the parties had agreed
on debt sculpting (aligning debt payments with cash flows to achieve constant DSCR), the one-time
levy would have had little to no effect on debt service payments in 2014.
Further, project owners should have generally been able to cover the extra costs incurred with
retained earnings or even cash stock accumulated in previous years. We therefore doubt that the onetime levy will have caused any actual debt defaults, particularly of larger market players. Our
discussions with market participants give little evidence of struggling projects, suggesting that most
owners have actually managed to deal with this temporary distress.
5. A MARKETPLACE FOR CASH COWS?
5.1. Secondary market
Despite the lack of distressed asset opportunities, there is interest in the secondary market. Private
equity funds from Europe, China and the US are looking for sound projects of reasonable size to
Attractive post-cut IRRs
have spurred interest in
provide steady cash flows. The aim would then be to package them into 50-100MW portfolios and
refinance them 2-3 years later, to increase margins. A few smaller players are pondering to sell their
assets to reduce exposure to country-level risk.
the secondary market.
There is no public record of any recent large-scale transaction, but the uncertainty created by the
snap election in January (see Section 6) could fluster project owners and force them to reconsider
their political risk exposure. We analysed potential buy-out values of wind and mainland solar
projects, in line with our assumptions made for the IRR analysis above. Figure 9 and Figure 10 show
ranges, of which the upper limit represents the seller’s expectation assuming a 10% (for wind)
and13% (for solar) hurdle rate, whereas the lower limit is depicting the equivalent buyer’s estimated
bidding price.
Figure 9: Buy-out value range for 2011 wind projects at 10%
equity hurdle rate
Figure 10: Buy-out value range for mainland solar projects at
13% equity hurdle rate
Higher FiT (Is)
2011 FiT
Higher FiT (Ma)
2011 Inc
Max support (Is)
2012 FiT
Max support (Ma)
2012 Inc
Min support (Is)
2013 FiT
Min support (Ma)
2013 Inc
0.5
1.0
1.5
2.0
2.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Source: Bloombcerg New Energy Finance; Note: Ma=Mainland, Is=Island, Inc= 20% Investment incentive
The buy-out value for 2011 wind projects lies in a EUR 1-2m/MW range (Figure 9), depending on the
level of applicable tariff, which in turn depends on whether or not the project received investment
© Bloomberg Finance L.P.2015
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
support (see section 2). A “fair” buy-out value, which would see seller and buyer returns converge,
could be at around EUR 1.6m/MW (see Figure 15 in the Appendix)4.
Buy-out values for mainland solar projects should be slightly higher, but would vary significantly by
connection year and support level (Figure 10). A 2012 PV project should achieve a “fair” buy-out value
of EUR 1.8m/MW (Figure 16 in the Appendix). In general, market experts estimate that negotiations
for utility-scale PV projects will cover a wide EUR 1.75-2.5m/MW price range, with aggressive
investors pushing for prices as low as EUR 1.3m/MW and sellers aiming for at least EUR 2.12.2m/MW.
5.2. Debt financing
Project debt financing
from international
lenders has all but dried
up in Greece.
Project finance by foreign commercial banks, in particular, has all but dried up due to the perceived
country risk since the start of the debt crisis. The last time foreign banks were involved in new project
finance were deals involving Unicredit for a 13MW wind project in 2010 and LBBW for a 4MW solar
project back in 2009. Since then, the market has only been served by a handful of domestic banks.
This has led all-in debt costs to rise, as a result of the liquidity shortage and the underserved market.
At the moment, larger players particularly active in the wind market, like Enel Green Power and Terna
Energy, are tending to refinance their projects by swapping some of their tied-up project equity for
new debt at better conditions. This will reduce their overall financing costs, with debt-equity ratios up
to 70/30. However, given the current state of Greek banks, it appears unlikely that conditions for bank
lending will improve anytime soon.
6. PROSPECTS FOR NEW PROJECTS
6.1. Wind
For new projects to be connected from 2015 onwards, feed-in tariffs for onshore wind range from EUR
82 to 110/MWh, depending on the size of the project, its location and whether the mainland project
decides to apply for the tax exemption. In reality, the tax exemption is for the majority of project
developers too much of a bureaucratic hassle and instead they opt for the higher FiT option, which
also seems more profitable over the lifetime of the project (see Figure 11).
The tariffs represent a significant premium on the system marginal electricity price, which averaged at
EUR 57.4/MWh in 2014. Project developers can therefore still hope to earn double-digit IRRs. This
makes Bloomberg New Energy Finance optimistic about new build in 2015, estimating that an
additional 300MW might come online this year.
6.2. Solar
Current tariff levels do
not incentivise any
further build-out of solar
capacity.
Support for new projects is slowly petering out. It appears that the boom of the Greek solar industry,
which saw tenfold growth in capacity between 2010 and 2014 (see Figure 1), has been brought to an
abrupt halt. The current legislation links the FiT for new projects to the average system marginal price
(SMP) from the previous year, adding only a premium of 10% for projects larger than 100kW. The
4
© Bloomberg Finance L.P.2015
This example assumes a 10MW mainland project without investment incentive.
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EMEA – POLICY – RESEARCH NOTE
11 February 2015
average SMP for 2014 was EUR 57.4/MWh, which sets the tariff for 2015 solar projects at EUR
63/MWh, well below our current LCOE estimate (see Figure 12).
Consequently, current conditions do not incentivise further PV build-out. However, a few projects in
the pipeline still have permits for the old tariffs and might therefore proceed, if they manage to connect
before the end of the year. For 2015, we expect 30-60MW of additional PV (supported via net
metering) capacity to come online. In the medium-term, new European regulations are expected at
some point to require a tendering process for projects larger than 1MW.
Figure 11: Greek wind IRRs (in %) for new projects connected
in 2015, by support level
120
20
18
Figure 12: 2014 Greek system marginal price (SMP), 2015
solar tariff and 2015 solar LCOE (EUR/MWh)
2015 solar LCOE
17.6
16
14.6
15.0
100
14.4
14
80
12
10.0
2015 solar
tariff
9.9
10
60
8
6
40
4
2
2014 avg. daily
SMP
20
0
Islands
Mainland Islands Mainland
Islands
2014 total
avg. SMP
Mainland
0
Higher FiT
Maximum tax
exemption
Minimum tax
exemption
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Source: Bloomberg New Energy Finance, Bloomberg Terminal.
7. IMPACT OF SNAP ELECTIONS
What the change in government might bring for the future of the Greek renewable energy market is so
far unclear. It seems obvious that for the moment policy-makers have other priorities, such as
following up on the promises to end austerity and reduce the country’s crushing debt levels. Early
actions by the new government indicate that a “Grexit” is not desired, and new finance minister Yanis
Varoufakis appears to aim for a restructuring of the debt in ways that would avoid the “haircut
terminology”.
Nonetheless, a few projections for the energy sector can be made based on the general business
environment, and the agenda and early actions of the coalition, consisting of the far-left Syriza party
and the right-wing Independent Greeks:
•
The power market liberalisation plans from the previous government will be put on hold. The
planned partial privatisation of Public Power Corporation (PPC), the national utility, has already
been cancelled. This will leave PPC with its strong market power, supplying 65% of the country’s
electricity. The tender for sale of 66% of the grid operator ADMIE has also been withdrawn.
•
© Bloomberg Finance L.P.2015
Further retroactive subsidy cuts are theoretically possible, but unlikely, as the damage to investor
confidence would probably outweigh short-term savings for the government. Tariffs for new
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projects are at reasonable levels for wind, and are already too low to incentivise any new-build
solar. We thus do not expect any further tariff adjustment, neither for new nor existing projects.
•
Support for further clean energy capacity will have to compete with the policy goal of reducing
retail electricity prices to alleviate pressure on low-income households. Should a renewable
energy policy reform be on the agenda, however, the auctioning mechanism for utility-scale
renewables, as prescribed by the EU state aid regulation from 2017, could prove a cost-effective
compromise, leading to competitive pricing and consumer benefits.
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Appendices
Appendix A:
IRR sensitivity analysis
The IRR sensitivity analysis is an output of BNEF’s proprietary Energy Project Valuation Model, to
which BNEF clients have access. The analysis shows how much the IRR would change, if a specific
parameter is increased or reduced by 10%.
Figure 13: IRR sensitivity analysis for a 2011 wind project
Figure 14: IRR sensitivity analysis for a 2011 solar project
Tariff 1 (EUR/MWh)
Equipment Cost (EUR/MW)
Balance of Plant (EUR/MW)
Construction Debt (%)
Tax Rate (%)
Fixed O&M (EUR/MW)
Tax Depreciation (%)
Senior Debt Spread (bps)
Variable O&M (EUR/MWh)
Development Cost (EUR/MW)
Senior Debt Swap Rate (%)
Construction Debt Spread (bps)
Reduced by 10.00%
Tariff 1 (EUR/MWh)
Equipment Cost (EUR/MW)
Construction Debt (%)
Tax Rate (%)
Balance of Plant (EUR/MW)
Fixed O&M (EUR/MW)
Senior Debt Spread (bps)
Tax Depreciation (%)
Development Cost (EUR/MW)
Construction Debt Spread (bps)
Senior Debt Swap Rate (%)
-26.62%
25.83%
-12.10% 13.40%
-7.25% 7.70%
-3.40% 4.05%
-3.22% 3.18%
-3.04% 3.03%
-2.90% 2.89%
-2.40% 2.38%
-1.83% 1.83%
-1.08% 1.09%
-0.84% 0.84%
-0.59% 0.59%
Increased by 10.00%
-20.34%
-13.33%
-3.99%
-3.54%
-2.82%
-2.54%
-1.92%
-1.64%
-0.82%
-0.57%
-0.39%
Reduced by 10.00%
21.33%
16.02%
4.85%
3.53%
2.93%
2.57%
1.92%
1.64%
0.84%
0.57%
0.39%
Increased by 10.00%
Source: Bloomberg New Energy Finance; Note: Project assumptions: IRR after subsidy cut, no investment support, located on the mainland. The change
is shown in real percentages (e.g. a tariff increase of 10% would lead to an IRR increase from e.g. 10% to 12.83%).
Appendix B:
Buy-out value sensitivity analysis
The buy-out value sensitivity analysis is an output of BNEF’s proprietary Energy Project Valuation
Model, to which BNEF clients have access. It calculates for a given equity hurdle rate the buyer and
seller IRRs depending on the agreed buy-out price.
Figure 15: Buy-out value sensitivity analysis for a 2011 10MW
mainland wind project, IRRs (%) and buy-out value (EUR)
Figure 16: Buy-out value sensitivity analysis for a 2012 4MW
mainland solar project, IRRs (%) and buy-out value (EUR)
30%
30%
25%
25%
Buyer IRR (%)
20%
Buyer IRR (%)
15%
"Fair" buyout value
20%
"Fair" buyout value
15%
Seller IRR (%)
10%
10%
5%
5%
Seller IRR (%)
-
10m
12m
14m
16m
18m
5m
6m
7m
8m
9m
Source: Bloomberg New Energy Finance; Note: No investment support assumed.
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About Us
Subscription details
Europe, Middle East & Africa (EMEA)
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Contact details
Copyright
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Janis Hoberg
[email protected]
Analyst, European Policy
+44 20 3525 8303
Anna Czajkowska
[email protected]
Head of European Policy
+44 20 3525 4363
Angus McCrone
[email protected]
Chief Editor
+44 20 3525 4795
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