Moody’s - La perspectiva estable para los precios de la energía en España y Portugal restringe…Neil Bisset, analista en Moody’s - Jueves, 02 de Julio
Moody’s publica el informe adjuntado sobre el sector de la energía en España y Portugal que comenta que Iberdrola y Endesa están más expuestos a los precio de materias primas que Energias de Portugal o Gas Natural porque una gran proporción de su generación proviene de plantas hidroeléctricas y nucleares de coste fijo, aunque EDP está bajo contratos de compra de energía hasta 2017 y Gas Natural genera una alta proporción de energía a través de Turbinas de Gas de Ciclo. Moody’s predice una perspectiva de precios de las materias primas energéticas estable.
Europe’s Electricity Markets In Iberia, Flat Power Price Outlook Provides Limited Upside for Producers » In Iberia, we expect wholesale power prices to trade in a range of €45-50 per megawatt hour (MWh) over 2015-2020. Our estimate for a relatively stable price trajectory reflects limited changes in the merit order over the period, modest demand growth, and flat commodity price estimates. This compares with the current one year wholesale forward power price of around €48/MWh. » Iberdrola (Baa1 stable) and Endesa (Baa2 stable), the largest power producers, are most exposed to the wholesale power price because a high proportion of their output is from fixed cost hydro and nuclear plants. EDP (Baa3 stable) is less exposed because more than half of the power it produces in Iberia is under power purchase agreements (PPAs), although its exposure will rise from 2017 once these have run off. Gas Natural (Baa2 stable) has more limited exposure because it has a high proportion of relatively expensive Combined Cycle Gas Turbines (CCGTs), and produces the lowest proportion of outright power. These groups’ exposure to a flat power price outlook is balanced by their scale and diversification, which includes large and stable contributions from regulated and contracted businesses, and, in certain cases, from substantial operations outside Iberia. » We see little change in either the volume or mix of gross installed capacity over the rest of the decade. This is because (1) modest demand growth and comfortable reserve margins in both Spain and Portugal deter investment in new capacity; (2) the region’s shift towards intermittent renewables output makes the authorities reluctant to sanction substantial thermal plant closures; and (3) subsidy cuts in Spain and license suspension in Portugal have slowed growth in renewable energy installations. » What could change our view on power prices. Higher than expected commodity prices would cause power prices to rise. Higher CO2 prices, driven by policy intervention in Europe, would also be positive for power prices. This would benefit Iberdrola, EDP and Gas Natural, and be broadly neutral for Endesa. Accelerated coal closures in Spain from 2017 would cause prices to rise gradually from 2017-2020. Conversely, a resumption of renewables growth combined with weaker than expected demand would be negative for power prices. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on http://www.moodys.com for the most updated credit rating action information and rating history. 2 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Power prices will keep to a narrow trading range through 2020 Flat commodity prices and a wide reserve margin will keep power prices in a narrow range We expect wholesale power prices in Iberia to trade in a narrow range of €45-€50/MWh over 2015-2020, firming towards the end of the period as coal closures build up.1 This reflects our flat commodity price estimates (see Unregulated Utilities Would Benefit from High CO2, but No Game Changer in Sight Yet ),2 a wide reserve margin, and slowly recovering electricity demand. This compares with (1) current one year wholesale forward power prices of around €48/MWh; and (2) and last year’s estimates of €47-50/MWh to 2016, and €49-52/MWh by 2020. The slightly higher anticipated ranges last year primarily reflected different commodity price estimates. Exhibit 1 Wholesale power prices (1-year forward baseload) in Iberia will remain in a narrow range Source: Moody’s Estimates, OMIP Scale and mix of installed generation capacity will not change significantly through 2020 After rapid growth of generation capacity in Iberia over 2003-13, a wide reserve margin and recent fiscal and regulatory reforms now act as disincentives to investment in additional generation capacity in Spain. In Portugal, which has a narrower reserve margin than Spain, we expect installed capacity to increase by 9% in the period to 2020. Given limited closures of thermal plant, scale and capacity mix in Iberia overall will change only gradually from 2014, when renewables (including hydro) accounted for approximately 51% of the peninsula’s 120.1 GW generation fleet. Against the background of a stressed economic environment, annual Iberian consumption declined by 6.5% over 2010-14. For Iberia in aggregate, we estimate the reserve margin at around 47% in 2014, based on estimated peak demand of 48 GW (the sum of Spain and Portugal’s peaks in 2014). This is up sharply from 34% in 2010, reflecting a combination of flat capacity and shrinking demand, as shown in Exhibit 2 below. We expect the reserve margin to narrow again in the period to 2020 as demand recovers. It will remain narrower in Portugal than in Spain, where it will be sustained by huge investment in renewables and CCGTs over the last ten years. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 3 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Exhibit 2 Iberian market reserve margin will remain comfortable Source: Red Electrica, Redes Energeticas Nacionais, Moody’s estimates Coal and gas-fired generation will continue to set the wholesale power price Rising output from renewables has pushed relatively expensive gas power plants out to the right of the Iberian merit order. Combined with commodity price weakness and lower demand, this has pushed one-year forward baseload prices lower, to €48/MWh on average in 2014 from over €50/MWh in 2011-13. We expect that both coal and gas-fired generation will continue to set the wholesale power price, with the level of demand determining whether coal or gas is the price setter. Under current regulatory and market conditions in Spain, less efficient domestic coal plants generate very little cash flow, and may begin to close. We therefore estimate that more expensive gas-fired generation will more frequently set the price as coal capacity gradually reduces, thereby boosting the average power price. Exhibit 3 Merit order: gas will set the price more frequently towards the end of the period 2014 Source: Red Electrica, Redes Energeticas Nacionais, Moody’s estimates 2020 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 4 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Limited upside for generators Iberdrola and Endesa are most exposed to Iberia’s generation market… Of the four largest Iberian generators, Iberdrola SA and Endesa SA3 are most exposed to the wholesale power price because a high proportion of their conventional output is from fixed cost hydro and nuclear plants. Energias de Portugal SA (EDP) also has a high proportion of fixed cost hydro output, but its exposure to power prices is limited by the guaranteed return on contracted generation assets in Portugal, which are under PPAs, or CMECs (Custos de Manutencao do Equilibrio Contractual).4 Iberdrola and EDP ’s wind assets add to their low marginal cost generation output (some of which also benefit from certain renewables incentives). Endesa and EDP also operate large coal fleets, which benefit from being at the margin much of the time, and from wider spreads when gas sets the price. Gas Natural Fenosa is less exposed to movements in the power price because it has the highest proportion of relatively expensive gas-fired generation within its fleet, and produces the lowest proportion of outright power. Exhibit 4 Iberdrola has the highest proportion of fixed cost output Generation output in 2014 (1) Iberdrola Iberdrola Gas Natural Gas Natural Endesa Endesa EDP EDP GWh % GWh % GWh % GWh % Technology Hydro 17,742 29% 4,275 14% 8,778 15% 15,944 40% Nuclear 24,431 40% 4,425 14% 24,762 43% 1,204 3% Coal 2,472 4% 5,622 18% 22,176 39% 14,543 36% CCGT 1,189 2% 14,143 46% 1,786 3% 1,163 3% Other thermal 2,010 3% - 0% - 0% 367 1% Conventional 47,844 78% 28,465 93% 57,502 100% 33,221 83% Renewables 13,208 22% 2,077 7% - (2) 0% 6,828 17% Total power output 61,052 100% 30,542 100% 57,502 100% 40,049 100% (1) Rainfall levels in 2014 were unusually high. Average annual hydro output usually represents a lower share of total production than in 2014. (2) Enel Group's Spanish renewables activities are reported as part of its subsidiary Enel Green Power. Source: Iberdrola 2014 results summary, Gas Natural 2014 annual report, Endesa 2014 Management Report, EDP 2014 annual report … but will see little upside from flat power prices through 2020 With power prices range-bound over 2015-2020, our ratings factor in little upside to Iberian utilities’ generation earnings over the next five years. This is reflected in their latest capex plans, which provide for very little development investment in domestic generation. Only EDP is currently developing capacity, with 1.5 GW new hydro plants in Portugal, most of which is pumped storage. These were 88% complete at end-March 2015. Prices will rise marginally from 2017 to 2020, benefitting Iberdrola, Endesa and to a lesser extent EDP. Credit quality continues to be based on scale and diversity Although we see little upside to generation earnings, Iberian power generators’ ratings outlooks are stable. This reflects our view that the worst is over in terms of earnings pressure from price declines and regulatory intervention,5 and that the power generators’ group earnings are underpinned by their scale and diversity. The table below shows how for the four large rated generators in Iberia, earnings from domestic generation and supply operations accounted for less than 40% of group EBITDA in 2014. Iberdrola, Gas Natural and EDP generate substantial earnings outside Iberia, which included large and stable contributions from regulated businesses. Although Endesa no longer holds the Enel group's Latin American assets, its Iberian earnings base is well diversified into regulated distribution and non-mainland activities. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 5 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Exhibit 5 Iberian utility groups are well-diversified by geography & business line EBITDA contribution by business in 2014 Iberdrola Gas Natural Endesa EDP €M €M €M €M Total EBITDA 6,965 4,853 3,090 3,642 Of which: Generation & Supply - Iberia 1,518 727 861 1,087 Renewables - Iberia (1) 420 55 - 361 Total Iberia generation/renewables 1,938 782 861 1,448 % total EBITDA Generation & Supply - Iberia 22% 15% 28% 30% Renewables - Iberia 6% 1% (2) 10% Total Iberia generation/renewables 28% 16% 28% 40% (1) Aggregate renewables' EBITDA reflects a combination of market exposure and regulated returns, which is a function of different regulatory regimes; Gas Natural value Moody's estimate based on renewables' share of production. (2) Enel Group/Endesa Spanish renewables activities are reported as part of Enel's subsidiary Enel Green Power. Source: Iberdrola 2014 results summary, Gas Natural 2014 annual report, Endesa 2014 Management Report, EDP 2014 annual report Pace of regulatory change has slowed Our wholesale power price estimates for Iberia incorporate the effects of regulatory measures taken in recent years to eliminate a structural imbalance between electricity system revenues and costs, including government subsidies. Costs exceeded revenues during the earlier part of the decade, creating tariff deficits in both Spain and Portugal. Improved regulatory backdrop reduces risks to generation earnings … Both countries have taken steps to cut costs and boost system revenues, but over a different timeframe. In Portugal, the government’s ‘Sustainability Plan’6 is designed to stabilize the deficit in 2015/16 at €5.3 billion before gradually reducing it to an estimated €600 million by 2020. The Spanish government, in contrast, targeted elimination of the deficit by 2014 through a combination of heavier cost cuts and taxes on generation. Both approaches are on track to deliver their objectives. The Spanish energy ministry, Minetur, expects surpluses of €11 million and €33 million in 2014 and 2015 respectively. In Portugal, the deficit at end-2014 had reached €5.3 billion, from €4.8 billion in 2013, in line with estimates, and is expected to stabilise from 2015. Progress towards equilibrium within the electricity systems of both countries reduces the risk of further ‘game-changing’ intervention in the Iberian wholesale power market, although in Portugal the cost of renewables continues to weigh on the system, and further fine tuning, for example to capacity payments, is likely. … but fiscal & regulatory differences continue to affect Iberian power market dynamics The measures so far adopted by Spain and Portugal to address their system deficits will continue to affect the comparative profitability of power generation, and the development of installed capacity within each country. Both countries have cut subsidies and imposed taxes on the generation industry to align better costs and revenues. However, the negative effect on generators’ profitability has been more pronounced in Spain, where sharper subsidy cuts were needed to secure the earlier elimination of the deficit. Differences between the measures adopted in Spain and Portugal will have the following effects on the Iberian power market, and on the cross-border interaction between installations in the two countries: Cost of production in Spain is inflated by generation taxes In Spain, Law 15/2012 introduced a series of taxes affecting conventional generation facilities from 1 January 2013. As a result, the procurement cost of generation in Spain is inflated by – inter alia - a general 7% tax on total revenues generated, and the green cent tax on consumption of electricity generated using gas, coal, fuel oil or diesel. All else being equal, Spanish generation assets will therefore be positioned further to the right in the merit order. Portuguese installations operating within the Iberian market should therefore benefit from higher load factors and margins than their Spanish counterparts. In October 2013, the Portuguese government responded to this potential industry ‘wind fall’ by introducing a MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 6 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS transitory charge (or clawback) of €2/MWh on off-peak generation, and €3/MWh on peak generation. The overall impact on EDP in 2014 was €12 million. The change to renewables’ remuneration in Spain also affects operators’ behaviour, reducing their incentive to run when the spot price is lower than their marginal cost of €3-4/MWh. Capacity in Spain and Portugal will reflect differences in incentives The future development of the installed generation bases of Spain and Portugal will be affected by the changes made to subsidy and capacity payments as part of the deficit reduction measures, although local demand and reserve margins will also influence this. For example: » An immediate cut to capacity payments for CCGTs in Spain from €26/kW to €10/kW, and a doubling of their contract period, 7 has prompted more requests by operators to close CCGT plants; and » Portugal has capped growth in renewables subsidies by suspending licensing of renewables installations since 2012. Spain, by contrast, has cut and altered the basis for remuneration of renewables, implying scope for some continued growth in the sector, albeit at a slower pace than previously envisaged.8 What could change our view on power prices The most likely causes of divergence from our price range estimates are: » Commodity prices differing from our estimates, which include coal prices in a range of $60-70/tonne, and gas prices of around €21/MWh. We estimate CO2 will trade at around €7/tonne for the period (see endnote 2). » Higher CO2 prices driven by a reform of the EU emissions trading scheme. This would push up power prices, benefitting some Iberian generators. We estimate that a €1/tonne increase in the price of CO2 raises Iberian power prices by around €0.6/MWh; a theoretical scenario in which CO2 rose to €20/tonne would thus add between 15% and 20% to our power price estimates, giving a range of €53 - €58/MWh. Exhibit 6 Iberian power price: sensitivity to CO2 at €20/tonne Source: Moody’s estimates MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 7 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS » More rapid Spanish domestic coal capacity closures combined with a rise in natural gas prices. This could cause prices to exceed our estimated range, rising to €55-60/MWh over 2017-20. » Weaker than expected electricity demand, or a new build-up of renewable capacity, which could result in lower price estimates. We estimate that Iberdrola would be the primary beneficiary of a rise in CO2 prices given the low carbon intensity of its Iberian generation fleet.9 EDP’s and Gas Natural’s fleets also have relatively low carbon intensity, and so would benefit from CO2 price rises. Conversely, Endesa would see little upside, given the higher carbon intensity of its large coal fleet. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 8 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Appendix 1: Approach Overview Our approach to analysing the power market in Iberia recognises that power generators operate within Spain and Portugal as if it were a single market. Buying and selling agents trade on the Iberian spot market regardless of whether they are in Spain or in Portugal. Their purchase and sale bids are accepted according to their economic merit order, until the 2,800 MW interconnection between the two countries is fully occupied. In 2014, the interconnection was fully occupied only 5% of the time, when the prices will have been set separately in Spain and Portugal – a mechanism referred to as market splitting. In the remaining 95% of the time, the Iberian market worked as an integrated one and the price of electricity was the same in Spain and in Portugal. Our estimates are therefore based upon the aggregation of data for each country – including, for example, the evolution of aggregate de rated capacity in Spain and Portugal, and the evolution of aggregate demand in Spain and Portugal. For simplicity, we have set aside the instances in which the interconnection between Spain and Portugal is fully occupied and therefore prices in the two countries differ. Exhibit 7 Historic pool prices: Spain and Portugal price differentials are limited and infrequent Source: OMIE MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 9 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Appendix 2: Power generation – our estimates Our central case for power price development over 2015-20 reflects our view that recovering demand and gradual coal capacity closures will leave CCGT to make up the shortfall, and that gas-fired generation will set the price in the market more frequently towards the end of the period. In addition to the commodity price estimates referenced in endnote 2, the central case reflects our estimates for the following variables: Electricity demand will shadow GDP growth, but at a discount as energy efficiency intensifies We estimate that electricity demand in the Iberian peninsula will grow at 1.3% a compound annual growth rate (CAGR) over 2015-20. This is based on our view of how demand will evolve in Spain and Portugal respectively, which is set out below. A faster growth outlook for both countries than in more mature European markets reflects (1) an element of rebound following the deeper recession they have experienced; (2) reduced scope for energy efficiency. Having contracted in the four years to 2014, Spanish mainland electricity consumption is set to recover from 2015. The rate of contraction slowed in 2014, to 1.2% (and just 0.2% on a weather/work day adjusted basis), which included 3.2% growth for industrial users. As GDP continued to expand, first quarter 2015 electricity demand growth of 2.3% (1.5% adjusted) provided further evidence of incipient recovery. We expect that electricity demand in Spain will grow at a CAGR of 1.3% during 2015-20. This includes a sharp 1.7% pick-up in 2015 and more gradual expansion thereafter, reflecting (1) steeper growth in the earlier years of recovery following the declines over 2011-14; and (2) a cumulative drag as energy efficiency measures gain more traction towards the end of the period. These projections imply a slightly flatter growth trajectory than that expected by Spanish energy regulator CNMC’s (Comision Nacional de Los Mercados y la Competencia), whose base case projects demand rising at a CAGR of 1.2% during 2014-17. 10 This would take consumption to 258TWh in 2017, a little higher than the 255TWh in 2017 on our trajectory. CNMC’s projection is also more conservative than Minetur’s 2% CAGR for 2015-20, which incorporates a 0.4% discount for energy efficiency. 11 Electricity demand in Portugal has also begun to show signs of recovery following a sharp 6% drop over 2011-12. The rate of contraction slowed to 0.7% in 2014 (and demand was flat on a weather/work day adjusted basis). As GDP continued to expand, first quarter 2015 electricity demand growth of 1.5% (flat adjusted) provided further evidence of recovery. We expect that electricity demand will grow at a CAGR of 1.4% during 2015-20. This is a little faster than the government’s lower growth scenario of 1%, but slower than its more aggressive projection of 3%. We have adopted the same approach to our estimates for demand growth in Spain and Portugal. These reflect the following assumptions: » Electricity demand growth will continue to shadow GDP growth through 2020. However, the pace of electricity demand growth will be discounted by improving energy efficiency, only partially offset by the shift of energy demand from rising electrification of transport and heating. To account for this, we have applied the 0.4% discount used by Minetur to capture declining energy intensity and improving efficiency to our own GDP forecasts for Spain. We apply the same haircut in Portugal because we assume consumption patterns are similar across the peninsula. » Moody’s Macro Board forecasts of real GDP growth from 2015 to 2019 of 1.7% CAGR and 1.8% CAGR for Spain and Portugal respectively. The chart below illustrates our estimates for combined electricity demand growth in the Iberian peninsula, which reflects the aggregation of our estimates for the two markets. While this is driven primarily by our view on Spain, which accounts for 83% of Iberian demand, it also reflects the broad alignment of our estimates for growth in each country. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 10 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Exhibit 8 Electricity demand: we estimate a gradual recovery over 2015-20 Source: Red Electrica, Redes Energeticas Nacionais, Moody’s estimates Generation capacity: scale and shape will not materially change over 2015-20 As expected, there was very little change in installed power capacity on the Iberian peninsula in 2014. In Spain, capacity closed 2014 at 102.3 GW, just 122 MW lower than 2013. In the smaller Portuguese market, there was also little change, with capacity rising just 0.5% to 17.8 GW. This stable picture follows a period of rapid capacity growth in Spain, where we estimate the reserve margin at 54% in 2014. In Portugal, where growth has been slower, we estimate the reserve margin at 13%. Differences between our estimates and those of the respective Transmission System Operators (TSOs) in Spain (41%) and Portugal (26%), reflect that our de-rating factor assumptions, although consistent, are lower than those used by the Spanish TSO, and higher than the Portuguese TSO. Overall, we do not expect significant changes in either the volume or mix of gross installed capacity in the Iberian power market over the rest of the decade: first, because comfortable reserve margins deter investment in new capacity (apart from pumped storage/ hydro); secondly, because security of supply considerations make the authorities reluctant to sanction substantial thermal plant closures; and finally, because subsidy cuts in Spain, and a moratorium on new installation licenses in Portugal, have slowed growth in renewables installations. » In Spain, having expanded every year since 2004, gross installed generation capacity will likely contract gradually by about 1.8% to approximately 98.5 GW in 2020 from a peak of 102.4 GW in 2013. Over the same period, we estimate that renewables’ share of gross capacity will move to 52.8% in 2020 from 49.4% in 2014. These gradual shifts reflect (i) the expected reduction of the thermal fleet given gradual closures of domestic coal plant and no new build; and (ii) very limited new capacity of renewable energy sources following cuts to incentives since 2013. » In Portugal, where the reserve margin is narrower, we expect capacity to grow by 9% to 19.4 GW, from 17.8 GW in 2014. Most new capacity is hydro, which together with renewables we estimate will account for 62.8% of installed capacity by 2020, from 59.6% at end-2014. Our expectations for each generation technology are based on the following: Nuclear: installed capacity should remain unchanged until 2020. The Spanish nuclear fleet, whose seven reactors were commissioned between 1971 and 1988, is subject to license renewal every 10 years. Licenses of all seven expire in 2020-2024, following the renewal in 2014 of the 1,003 MW Trillo plant, which was commissioned in 1988. Coal: In Spain the termination of domestic coal subsidies from end-2014 has changed the economics of domestic coal-fired plants, which account for around half of the 11 GW of installed coal capacity. Under current regulatory and market conditions, less efficient MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 11 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS domestic coal plants generate very little cash flow, and there is little incentive to invest in Selective Catalytic Reduction (SCR) in order to comply with the Industrial Emissions Directive (IED). While most plants will obtain derogation from the requirements of the IED and will therefore be available to run for 17,500 hours over 2016-2023, we estimate that half domestic coal capacity will close gradually from 2015 to 2020. Endesa, for example, has requested authorisation to close Compostilla 2 (148 MW) in 2015, and we think it will likely seek authorisation to close the remaining units at Compostilla 3, 4 and 5 (904 MW in total) over the coming years. It is possible that the introduction of a capacity payment (probably linked to investment in SCR), which is currently under discussion in the Ministerial Order draft sent by Minetur to CNMC, could encourage domestic coal plants to remain open. However, there is little clarity at this point. By contrast, our expectation is that international coal plants will invest to ensure compliance with IED’s DeSOx/DeNOx regulations, and will therefore continue to operate well beyond 2020. Some have already announced plans: Viesgo, formerly known as EON Generacion, ((P) B1 stable) is to spend €55 million on the 589 MW Los Barrios plant; and EDP is to ensure that approximately 85% of its Iberian coal fleet will be compliant. We expect few coal unit closures in Portugal, as long as the price of CO2 remains low. Differential tax regimes mean that thermal units in Portugal will continue to enjoy a cost advantage over Spanish competitors, which bear the energy and fuel tax. CCGT: We see no prospect of an increase in CCGT capacity over the period given that we expect wide reserve margins and low load factors to prevail in the Iberian market. In Spain, the government’s reluctance to commit to multi-year remuneration sought by the utilities (unsurprising given high reserve margins) may deter mothballing, and prompt more outright closures – although this remains subject to government authorisation. In Portugal, we expect limited CCGT shutdowns because the absence of generation taxes gives them a cost advantage over Spain, and because capacity payments are underpinned by the country’s narrower reserve margin. Most plant operates as back-up; beyond 2,000 hours CCGTs begin to pay the €2-3/MWh off-peak/peak clawback. In Spain, by contrast, legislation (RD 9/2013) to cut capacity payments has reduced incentives to keep open plant that is operating at very low load factors. Even Gas Natural, which enjoys higher load factors than its peers, ran at just 24% load factor in 2014. Having cut costs as much as possible through mothballing, operators are likely also to consider permanent closure. However, despite very low load factors and the cuts to capacity payments we have assumed that the majority of CCGT plants will remain available (although mothballed) at least until 2020 because: » most will continue to be eligible for capacity payments (albeit at reduced rates) and retain some option value, at least until the impact of IED on coal capacity becomes clearer; and » even where authorisation is sought to close, this is not always granted by the grid operator. Earlier in 2015, for example, Iberdrola was declined permission to close Arcos III, its 1.6 GW CCGT at Cadiz. Our estimates for CCGT/OCGT capacity in Spain are therefore based on the view that permanent closures will be limited to the 2.6 GW of plants where authorisation has been granted, which include Endesa’s OCGT at Foix (520 MW), Iberdrola’s 800 MW CCGT at Castellon, and Viesgo's (formerly EON Generacion) 400 MW plant at Taragona. Although our estimates for CCGT closures affect our estimates of the reserve margin in Spain, they have little effect on wholesale price formation given the amount of overcapacity. Renewables: We expect limited growth in renewable energy capacity in both Spain and Portugal given the wide reserve margin and cuts to returns and incentives in both markets. Moreover, the proposed Royal Decree in Spain on self-consumption appears designed to deter localised installation of photo-voltaic through its provision for payment of a ‘back-up fee’ for every kWh self-consumed to maintain the back-up service provided by the grid. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 12 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS We have therefore assumed that there will be no material new renewables capacity built in Iberia, although we have sensitised our price estimates for the effects of growth of up to 4 GW, in line with Minetur's estimates. Hydroelectric: In Spain, we expect a 1.1 GW increase in hydroelectric capacity by 2020, reflecting mainly the completion of the 875 MW (in 2015) pumped storage capacity currently under construction by Iberdrola. A similar amount will be added in Portugal over 2015-16, where EDP is building/repowering 5 hydro plants, which were 88% complete at March 2015. These will bring installed capacity in Portugal to approximately 7.2 GW by end-2016. Interconnection: Given currently wide reserve margins, we see interconnectors in Spain more as an export outlet for inflexible renewable energy than as underwriters of domestic demand. Capacity between Spain and France recently doubled to 2.8 GW (roughly 6% of peak demand) from 1.4 GW upon completion in 2015 of the HVDC link between Santa Llogaia and Baixa across the eastern Pyrenees. Interconnection capacity between Spain and Portugal comprises 2.8 GW from Portugal to Spain, and 2.2 GW from Spain to Portugal. Current plans are to increase capacity from Spain to Portugal by 2017, which will further reduce the incidence and breadth of price differentials. However, we exclude interconnection capacity in estimating each market’s reserve margin. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 13 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Exhibit 9 Installed capacity trends and estimated 2010-2020 SPAIN PORTUGAL IBERIA Source: Red Electrica, Redes Energeticas Nacionais, Moody’s estimates MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 14 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS De-rating capacity factors We set out our de-rating capacity estimates in the Sector In Depth ' European Unregulated Utility Sector: EU Energy Policy and National Interests Conflict at the Expense of European Unregulated Utilities’ Credit Quality ' published in 2014. Their application to estimated gross generation capacity is reflected in the illustrative merit order in Exhibit 3. Average cost/MWh for each technology, which incorporates taxes, logistics and other costs We calculate our power price forecasts as the weighted average of the procurement cost of the technologies setting the price, mainly coal plants and CCGT plants. Coal and CCGT plants procurement costs are mainly driven by Moody’s CO2, coal, and gas price assumptions, and our assumption of average coal and CCGT plant efficiency of 36% and 50% respectively. Procurement costs also incorporate electricity taxes, fuel taxes, and operating costs. In order to determine the average frequency with which coal and CCGT plants set the price in a given year, we assume that coal plants set the price when hourly demand is lower than the cumulative Moody’s de-rated capacity for coal, while CCGTs set the price when hourly demand is higher. We estimated the shape of the demand distribution for the years from 2015 to 2020 based on the average distribution in the 2012-201412 period increased by the electricity demand growth rate we have described. Following this approach we estimate that in 2015 coal plants set the price 40% of the time, gas plants set the price 51% of the time, while renewables and nuclear plants set the price 9% of the time. We estimate that by 2020, as electricity demand in Iberia rises, the frequency of gas plants setting the price would also increase. The Exhibit below shows our estimate of the frequencies of coal plants and CCGTs setting the price during 2012-2014 in period in Iberia.11. For the years from 2015 to 2020, we expect that hourly demand distribution in Iberia will maintain the same shape as in the 2012- 2014 period, and will increase at the electricity demand growth rate we have described. Exhibit 10 Typical electricity demand distribution in Iberia Source: CNMC, Moody’s estimates MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 15 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Appendix 3: Recent evolution of electricity generation and prices in Iberia Declining demand supports high reserve margin in Iberia Despite real GDP growth in Spain and Portugal of 1.39% and 0.92% in 2014, electricity demand in the two countries deteriorated by 1.2% and 0.7% respectively (unadjusted for weather/work days) reflecting the drag effect of energy efficiency on consumption. Exhibit 11 Historic correlation between electricity demand and GDP is weakening SPAIN PORTUGAL Source: Red Electrica, Redes Energeticas Nacionais Since 2010, very little new thermal generation capacity has been commissioned in Iberia. CCGT capacity, the growth engine for most of the last decade, remained unchanged at approximately 29.2 GW in 2014, of which 3.8 GW in Portugal and 25.4 GW in Spain. Gradual closure of Open Cycle Gas Turbine (OCGT) capacity led to total gross thermal capacity contracting slightly to an estimated 65.5 GW in 2014 from a peak of 67.6 GW in 2010. By contrast, growth in renewables continued strongly over 2009-13, although its pace decelerated sharply in 2013 and 2014 as cuts in subsidies took effect. On-shore wind increased to 27.4 GW while solar reached an estimated 7.1 GW in 2014, eight years after the first solar panels were installed. This accounted for the bulk of the overall rise in capacity from 110.3 MW in 2009 to an estimated 120.1 GW in 2014. Relative growth trends caused renewables’ share of Iberia’s generation mix to rise from 46% in 2009, to 51% in 2014. Over the period, estimated peak MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 16 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS demand has ranged from 48.3 GW to 53.9 GW in Iberia. The exhibit below shows how the combination of increased capacity and shrinking demand led the reserve margin to widen from 34% to 47% in 2014. Exhibit 12 Iberia Reserve Margin is Set to Narrow Over Time Source: Red Electrica, REN, Moody’s estimates Coal and gas-fired generation continue to set the wholesale power price The large share of renewables capacity in the energy mix has increasingly influenced wholesale power price formation in Iberia. Given current commodity prices, this affects Iberian power prices as follows: » Power prices can be volatile when renewables output is high, as Exhibit 13 below shows. Exhibit 13 Monthly Renewables production and monthly pool prices in Spain Source: Red Electrica, OMIE » High renewables output has pushed relatively expensive gas power plants out to the right of the merit order. Given current commodity prices, either coal or gas-fired plant sets the wholesale power price ‘at the margin’, depending on demand. One year forward baseload prices therefore incorporate the market’s expectations of the relative contributions to price setting by each technology. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 17 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Exhibit 14 Historic demand coverage in Iberia Source: Red Electrica, REN » Combined with commodity price weakness and lower demand, this has pushed one year forward baseload prices lower, to an average €48/MWh in 2014 from over €50/MWh in 2011-13. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 18 30 JUNE 2015 EUROPE’S ELECTRICITY MARKETS: IN IBERIA, FLAT POWER PRICE OUTLOOK PROVIDES LIMITED UPSIDE FOR PRODUCERS Moody's Related Research Sector In Depth » In Britain, Falling Demand and New Capacity Will Squeeze Coal and Gas, June 2015 (1006010) » In Poland, Low Prices and Political Uncertainty Weigh on the Sector, June 2015 (1005820) » In Ireland, Power Prices to Trend Lower Amid Regulatory Uncertainty, June 2015 (1005581) » In France, Exposure to Weak Wholesale Power Prices Will Continue to Grow, June 2015 (1005748) » Unregulated Utilities Would Benefit from Higher CO2 Price, but No Game Changer in Sight Yet, June 2015 (1005857) » In Italy, Power Prices to Fall on Weak Demand, Low Gas Prices, June 2015 (1005764) » In Germany, Low Power Prices Keep Pressure on Generation Earnings, June 2015 (1005769) » In Nordics, Generation Earnings Remain Pressured by Low Power Prices, June 2015 (1005574) » European Unregulated Utility Sector: EU Energy Policy and National Interests Conflict at the Expense of European Unregulated Utilities’ Credit Quality, July 2014 (172091) Outlook » EMEA Electric and Gas Utilities: Easing Pressure on Generation Earnings and Less Intrusive Political and Regulatory Intervention Support Stable Outlook, November 2014 (1000593) Credit Focus » EDP - ENERGIAS DE PORTUGAL SA: Credit Profile Supported by Diversified Business Mix and Capital Discipline, June 2015 (1005352) New Issuer report » E.ON Generacion SLU, March 2015 (179808) To access any of these reports, click on the entry above. Note that these references are current as of the date of publication of this report and that more recent reports may be available. All research may not be available to all clients. MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 19 30 JUNE 2015 EUROPE’S ELECT
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