WIND POWER IN THE SPANISH ELECTRIC MARKET Alberto Cea March 2015 - - PowerPoint PPT Presentation

WIND POWER IN THE SPANISH ELECTRIC MARKET

Alberto Ceña

March 2015

REGULATORY FRAMEWORKS

3

 Until they are tackled, the numerous conditions affecting both the market and the internal regulation of renewables pose Obstacles to renewables development from the outset  Main conditions may be defined:

Technological development Pay ment mechanisms Transmission development

• Capital intensive

investments

• High investment cost in

developing technology and learning curve

• Support policies required to

encourage investments

• Non-existence of investment

support deters development

• The proliferation of clean energy

sources requires:

• Tranmission network access.
• Grid investments, to ensure

proper functioning

• Dispatch priority

Source: Banco Santander and own elaboration

Immediate Obstacles

Administrative procedures

• Land, special levies and

biased treatment

• Environmental processing:

lack of experience

• One stop shop – or as close

to one as possible

30 60 90 120 1700 1900 2100 2300 2500 2700 2900 LCOE €/MWh

LCOE (€/MWh) IN DIFFERENT WIND FARMS CONDITIONS

100% Equity 80% debt / 20% equity (r: 6,5%) 80% debt / 20% equity (r: 7,5%) Average pool price

Nominal hours Interestrate

Regulatory frameworks should cover the present costs

• f producing wind power

Nominal hours (CAPEX 1,2 MM€/MW)

1700 1900 2100 2300 2500 2700 2900

CAPEX (MM€/MW) (2.100 hours)

1485 1325 1200 1090 1000 935 869

Incremento del incentivo Fuente: AEE

Remuneration systems

5

 Despite falling investment costs in different technologies (trending towards grid parity), there still seems to be a need for remuneration incentives to make investments possible  We can identify different incentive shemes around the world

• The renewables producer is entitled to sell all power generated to the grid either at an established fixed price or at the hourly pool price plus an “incentive”.
• Characteristics:
• Price or incentive fixed by law
• The power produced has guaranteed priority grid access
• Extensive duration of incentives (15-20 years)

Feed in Tariff

• The regulation obligates providers and producers to source a percentage of power to renewables
• To comply with that obligation, each agent must deliver a Green Certificate for each MWh of renewable power supplied
• The

Green Certificate is sold by the renewable power generator based on actual production either through a specially organised market or directly to the power provider/producer

• Accordingly, the renewables producers’ income source is double : the market price + green certificate value

Green certificates

• The regulation incentivises renewable energy deployment through auctions for different technologies inviting bids from interested investors
• The acution establishes a maximum price, so fostering competitiveness among investor bidders
• The utilities are obliged to buy all power produced throughout the duration of the PPAs allocated

Auctions

• The State promotes renewable energy deployment through direct or indirect fiscal incentives for the producer
• This system applies in USA, mainly through tax credits that can be sold to third parties (Production Tax Credits or PTC)

Incentivos Fiscales

X

Tariff

• It should give enough medium and long term vision
• It has to take into account the learning curve of the

technology.

Proj. IRR

1

Key parameters Main comments

• Initial value
• Duration and up-dating
• Technical incentives

Generation

• It is important to have an accurate evaluation of the wind

conditions for all WTGS

• Important also an adequate selection of the model and

type of the WTGs

2

• Accurate evaluation of the

wind conditions and WTG type.

• Curtailments risks

CAPEX

• The size in MW should not be the main economic criteria

for selecting a WTG

• Known margins could affect to the final price of the WTG

3

• WTG costs.
• BOP costs

OPEX

• Maintenance and
• peration
• Rents, taxes and social

returns Reques- ted Profita- bility

>

Capital cost (WACC)

• It should be based in the sector average, which is often not

easy to evaluate.

4

• Leverage level
• Rate of interest
• Country risk

Key parameters to define the tariff incentive

4

• As low as possible without affecting Wind Farm

Reliability.

• Impact of local and regional restrictions

Source: AEE

Former regulatory framework based on premiums over the pool price (€/MWh):

• Regulated, fix feed in tariff: variable premium
• Pool price + premium with a cap and floor remuneration

• It has been mainly driven by the tariff deficit (consumers do not pay all the

electrical system costs).

• No more premiums (€/MWh) over the spot price, they have been changed for

incentives to the investment (€/MW).

• To guarantee a project IRR is of 10 years bond + 300 bp. In 21014 was 7,398%
• All the installations should be assimilated to standard projects. For wind it is

related to the starting year of operation

• The sole variable income is the spot market price, but with a cap and a floor too.
• The incentives are reviewed each three years following the market prices and each

six following the public bonds rate of interest

Main changes of the regulatory reform

Intallations standard >5 MW. The incentive Rinv, is received to complete the 20 years of project economic life

9

CODE STARTI NG OPERAT ION YERA CAPEX (€/MW) Rinv 2014- 2016 (€/MW) Minimum equivalent hours 2014-2016 Operational trehsold Uf Anual 2014- 2016 IT-00644 1994 1.025.000 IT-00645 1995 1.025.000 IT-00646 1996 1.025.000 IT-00647 1997 1.005.000 IT-00648 1998 979.000 IT-00649 1999 965.000 IT-00650 2000 960.000 IT-00651 2001 957.000 IT-00652 2002 957.000 IT-00653 2003 968.000 IT-00654 2004 1.075.000 8.294 1.048 629 IT-00655 2005 1.120.000 19.484 1.095 657 IT-00656 2006 1.175.000 41.342 1.101 661 IT-00657 2007 1.250.000 74.254 1.050 630 IT-00658 2008 1.367.000 107.220 1.050 630 IT-00659 2009 1.431.000 115.550 1.050 630 IT-00660 2010 1.528.000 124.803 1.050 630 IT-00661 2011 1.445.000 109.114 1.050 630 IT-00662 2012 1.398.000 104.995 1.050 630 IT-00663 2013 1.366.000 101.312 1.050 630 IT-00664 2014 1.366.000 101.157 1.050 630 IT-00665 2015 1.366.000 101.240 1.050 630 IT-00666 2016 1.366.000 101.381 1.050 630

Wind farms affected by the regulatory reform: all of them are merchan or quasi merchant plants

Año Total Anual (MW) Potencia eólica instalada ACUMULADA (MW) Tasa de variación (%) 1989 1990 1 1991 1 1 1992 12 13 1993 14 1994 5 19 1995 67 86 1996 116 202 1997 199 401 1998 311 713 1999 720 1.433 101,04% 2000 906 2.339 63,22% 2001 1.156 3.495 49,43% 2002 1.506 5.000 43,08% 2003 1.160 6.160 23,20% 2004 2.280 8.440 37,00% 2005 1.552 9.991 18,39% 2006 1.578 11.569 15,79% 2007 3.502 15.071 30,27% 2008 1.613 16.684 10,70% 2009 2.455 19.139 14,71% 2010 1.487 20.626 7,77% 2011 1.048 21.674 5,08% 2012 1.110 22.784 5,12% 2013 175 22.959 0,77%

Change of remuneration 25 MW Wind farm

11

1.000 2.000 3.000 4.000 5.000 6.000 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Retribución después de la reforma Retribución antes de la reforma

miles €

2003

1.000 2.000 3.000 4.000 5.000 6.000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Retribución después de la reforma Retribución antes de la reforma

miles €

2004

1.000 2.000 3.000 4.000 5.000 6.000 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Retribución después de la reforma Retribución antes de la reforma

miles €

2008

1.000 2.000 3.000 4.000 5.000 6.000 7.000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Retribución después de la reforma Retribución antes de la reforma

miles€

2012

TECHNICAL AND ECONOMIC MARKETS OPERATION

Electric market processes

DAY-AHEAD MARKET (D) Reference price

12:00 TECHNICAL CONSTRAINTS Day-Ahead Result Hourly Final Schedule FORWARD CONTRACTS (Price hedging mechanisms)

INTRADAY MARKETS REAL TIME

D-1 D

Different sessions of the day ahead and intraday markets

00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 00

27 hours

..

24 hours 20 hours 17 hours 13 hours 9 hours 27 horas

..

DAY AHEAD MARKET D DAY AHEAD MARKET D+1 INTRA DAY MARKETS

CLOSING TIME 12

Wholesale electric market managed by the XP (OMIE ) and Ancillary services programmes managed by the TSO (REE)

15

Daily Market Intra-day Market: Sessions 1 to 6

Market Operator System Operator

Previous information DM Reception of nominations

Resolution of technical constraints

Secondary Regulation

Resolution of technical constraints Resolution of technical constraints

Deviation management Tertiary Regulation

All the offers are agregated by technology

First block: Energy 100,0 MWh, at 10,00 Euro/MWh Third block: Energy 130,0 MWh, at 80,00 Euro/MWh Second block: Energy 110,0 MWh, at 30,00 Euro/MWh

Production Offers integration

Undispatchable plants

All the purchase offers are agregated inclujding bilateral contracts First block: Energy 15,0 MWh, a t180,30 Euro/MWh Third block: Energy 3,0 MWh, at 20,00 Euro/MWh Second block: Energy 10,0 MWh, At 100,00 Euro/MWh

Purchase Offers integration

COGEN ESPAÑA. ASOCIACIÓN ESPAÑOLA PARA LA PROMOCIÓN DE LA COGENERACIÓN

The crossing point fixes the energy finally matched (i.e. 22.000 MWh) and te marginal price (i.e. 40 €/MWh)

Both curves cross in the marginal price

The final price is in each our determined by the complex offers

19

Modification of programmes for complex offers:

• Minimum income
• Power gradient
• Stop condition
• Non divisible offers

Production offers not matched in Spain

20

Wind farm 1 Wind farm 2 Wind farm N

Programming +prediction (12:00h/D-1) Intraday Adjustment

TECHNICAL CONSTRAINTS SOLUTIONS

OMIE

(Market operator)

DAILY MARKET

REE

(System operator) 6 INTRADAY MARKETS

MATCHES RESULTS

Programming adjusted 6 times per day

International Bilateral C. Domestic Bilateral C.

Real Time Process

OTHER TECHNICAL PROCESSES Ancillary Services BASE OPERATING SCHEDULE OPERATING HOURLY SCHEDULE FINAL HOURLY SCHEDULE VIABLE DAILY SCHEDULE

Schedule

6 MERCADOS INTRADIARIOS

Wind energy participate in all sessions

21

GLOBAL METEOROLOGICAL DATA

FORECASTERS

WIND FARM PRODUCTION FORECASTS

Offer Unit 1 Offer Unit 2 Offer 1 Deviation 20% DAY AHEAD MARKET<10.00 A.M Offer 2 Deviation 17% DAY AHEAD MARKET<10.00 A.M REDISPATCHING INTRA- DAY MARKETS DEVIATION: 13% REDISPATCHING INTRA- DAY MARKETS DEVIATION: 15% Wind Farm Deviation 30 % Wind Farm Deviation 30 % Wind Farm Deviation 30 %

Wind farms forecast their production for the day market to optimize the balancing power

Wind farm individual deviation: 30% Offers are integrated in portfolio from different bassins Final devistion 11%-13%

22

y = -0,0003x + 5,0921 R2 = 0,4031

1 2 3 4 5 6 7 1000 2000 3000 4000 5000 6000 7000 Wind power (MW) Pool market (cent€/kWh)

WIND ENERGY SUBSTITUTES MORE EXPENSIVE POWER PLANTS AND THEN POOL PRICE IS REDUCED Reduction of prices is estimated in around 2-3 €/MWh every 1000 MW of wind power in the system and it almost covered the cost of premium linked to wind energy

RELATIONSHIP BETWEEN WIND ENERGY AND POOL PRICE IN THE DAILY MARKET

y = -0,0002x + 5,0193 R2 = 0,6085 1 2 3 4 5 6 1000 2000 3000 4000 5000 6000 7000 Wind power (MW) Pool market (cent€/kWh)

MWh Price (€/MWh) Gas Day Wind & Nuclear Night Peak Demand Offer Fuel oil CCG T

Source: RISOE y AEE

MWh Price (€/MWh) Gas Day Wind & Nuclear Night Peak Demand Offer Fuel oil CCG T MWh Price (€/MWh) Gas Day Wind & Nuclear Night Peak Demand Offer Fuel oil CCG T

Source: RISOE y AEE

23

IMPACT OF THE WIND ENERGY IN THE POOL MARKET

1,5 2,0 2,5 3,0 3,5 4,0 4,5 5,0 5,5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours cent€/kWh

<1000 MW 1000 MW-2000 MW 2000 MW-3000 MW 3000 MW-4000 MW 4000 MW-5000 MW >5000 MW Fuente: AEE

• This graph shows by levels of wind generation the average pool price per hour
• The range <1000MW shows the average pool price by hour if the contribution of the wind energy

was null.

• The following curves show increases of wind production, this shows how the pool price decrease

when increase the contribution from wind power.

Pool market (January 2007-July 2007)

Average deviation of wind farms offers is between -13% and +11%

24

• 5000
• 4000
• 3000
• 2000
• 1000

1000 2000 3000 4000 5000

RE Eolico medida-programa

RE Eolico medida-programa

Fuente:ESIOS

Deviations of the load are still much more important than wind power differences

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In absolute terms, the deviation of the demand is much more important than the wind generation one, which, moreover,

2.935 3.937 2.959 1.096 1.041 1.564 2.269 5.104 7.269

2.000 4.000 6.000 8.000 10.000 12.000 14.000 2008 2009 2010 GWh

Net demand deviation Wind Energy deviation helping the System Wind Energy deviation against the System 4.031 4.978 4.523

13,3% 12,4% 11,0% 10,7%

0,8% 1,9% 2,6% 3,7%

0% 2% 4% 6% 8% 10% 12% 14%

2008 2009 2010 2011

% Wind Energy Deviation % Demand Deviation

Deviation (%)

Matches results

Wind farm 1 Wind farm 2 Wind farm N

Programming +prediction (10:00h/D-1) Intraday Adjustment

• Technical constraints

solutions

• Other technical
• perating processes

OMIE

(Market operator) DAILY MARKET

REE

(System Operator)

INTRADAY MARKETS

OPERATING HOURLY SCHEDULE (PHF)

Programming adjusted 6 times per day

Wind energy in the electrical market

• The main incidence of wind power is in tertiary regulation (between 15’ and 3 hours) and management of

deviations between generation and load (before closing day and intraday markets).

• Unforeseen variation of power demand is more important (with 40% 0f deviations) than prediction errors
• f wind power plants (slightly over 30%).
• Costs in balancing power caused by wind energy is paid by wind producers. The unitary cost was of 1,4

€/MWh much lower than initially foreseen.

INCIDENCE OF WIND ENERGY IN THE BALANCING POWER:

The coordinated operation of the system is crucial

27

CECRE

TSO: Centro de Control centralizado del Régimen Especial

…

Parque R.E. 1 Parque R.E. 2 Parque R.E. n

CC1 CC2 CCn

Solución provisional

• CECRE: REE Control Center of

the Renewable Energy

• CC: Control Center of

generation.

All wind farms over 5 MW of capacity are controlled by the TSO

28

...

WIND FARM Remote control

VSAT

...

WIND FARM

...

WIND FARM

HUB CECRE Point by Point Control Center ADSL Dedicated line

CECRE REASONS FOR CURTAILMENTS

• Overload risks in transmission and distribution grids.
• Risks of lost of power by transient instability (LVRT).
• Limited short circuit capacity of the installed wind farms which could restrict the operation of

neighbourhood protections.

• Excess of generation which cannot be consumed by the demand (limited exchange capacity with France).

Limitation of wind energy production

• Nov 9th, 2010. Spain.

The TSO orders reduce wind energy production

29

Demand coverage reached in the night Order to reduce production

Wind power curtailments in 200-2014 (without compensation)

30

3,6 6,9 202,2 19,3 93,0 1140 502 27,9 5,6 27,5 13,3 13,9 15 28,5 57,4 85,5 40,7 14,2 10 15 48

200 400 600 800 1.000 1.200 2008 2009 2010 2011 2012 2013 2014 Excedente generación RdT RdD Huecos de tensión 108 GWh 70 GWh 315 GWh 73 GWh 121GWh 1.165GWh 517GWh GWh

• Thank you very much for

your attention