ALBA SOLUZIONI. The Italian gas and power markets. Peter Crilly Energy Commodities Conference May 2018

Transcription

1 Consultancy and information services in energy and finance The Italian gas and power markets Peter Crilly Energy Commodities Conference May 218 1

2 The Italian gas and power markets Alba Soluzioni is an independent consultancy operating in the energy and finance sectors in Italy Italian gas & power market report Gas e Elettricità Oggi ---- GeEO - Italian Gas & Power Italian Regulatory Alert Service AlbaStack power price forecasting service AlbaFlows daily gas service Consultancy services, seminars and workshops info@albasoluzioni.com This presentation has been prepared using publicly available information in addition to Alba Soluzioni s proprietary Italian market price information. The interpretation of publicly available information and the analysis and conclusions derived represent Alba Soluzioni s viewpoint as an independent observer of the markets. Whilst Alba Soluzioni has no reason to believe that there are any inaccuracies or defects in the information and analysis presented, there are no representations or warranties, express or implied, to the fitness of such information for any purpose.

3 The Italian gas and power markets NL & Norway TENP/Transitgas Passo Gries Interaction with Northern markets balances Italy Russia TAG Tarvisio Gas market Supply Snam LNG Panigaglia OLT LNG Algeria TTPC Mazara del Vallo Gorizia ALNG Rovigo/Cavarzere Libya Greenstream Gela Indigenous production now covers < 1% of consumption Diversified supply from North Sea, Russia, Algeria,Libya and LNG terminals A lot of the capacity is covered by long term Take or Pay contracts Demand Distribution Power Industry

4 The Italian gas and power markets Power market 33.6 CCGT is usually the marginal technology 39.8 CCGT CIP6 & CHP Import Export Coal 25 2 Oil&Gas&GT 15 Hydro Other renewable Switzerland France Slovenia Austria Greece Enel A2A/Edipower Edison EPH Tirreno P Eni Sorgenia EGL GdF Others Total CCGT CIP6 & CHP Coal Oil&Gas&GT Hydro Other renewble Total

5 The Italian gas and power markets Asia LNG PSV Italian gas price influences Oil indexed contract Spot/long term spread TTF PSV/TTF spread Coal generation Coal CO2 HH US shut in Variable export 5

6 Italian gas and power market update Italian power As CCGT is usually the marginal technology, it can be helpful to look at the Italian power prices as being the sum of CCGT gas cost CCGT CO 2 cost and the clean spark spread Power prices respond to changes in gas and CO 2 prices Power market fundamentals drive the spark spread Italian power clean spark spread CO2 PSV gas 6

7 PSV premium Spreads to Passo Gries Capacity from Germany to Switzerland is not enough to provide maximum import at Passo Gries So gas needed from France at higher transport cost to get Transitgas pipeline to maximum Transportation costs for day ahead capacity assuming full utilisation ( /MWh) VTP NCG TTF PEG Exit from Oltingue Exit from Wallbach Exit Bocholz Exit from Arnoldstein Transitgas Entry Passo Gries Entry Tarvisio Commodity to PSV 21 mmcm/d Long term capacity fee 53 mmcm/d 59 mmcm/d

8 PSV premium PSV forward prices have converged with Northern hubs Year ahead PSV premium trading between variable and total transportation cost from Germany but spot spread range is wider PSV and TTF GY ahead prices in /MWh PSV TTF

9 PSV premium TENP issues reduce German exit capacity and and 218 until 8 March German exit mmcm Passo Gries Flow mmcm Spot PSV/TTF /MWh German exit capacity at Wallbach mmcm/d Passo Gries Flow mmcm Spot PSV/TTF /MWh Maintenance has reduced exit capacity from Germany to Switzerland in summer 217 and revealed corrosion defects on one of the two pipeline strings which is to be closed until September 22 for repair - capacity down from 53 to 3 mmcm/d So max Passo Gries import capacity = (Oltingue) Swiss demand And PG demand above 3 mmcm/d Swiss demand comes from France PEFG Nord at around TTF -.2 gives cost of marginal supply of TTF + 3. /MWh

10 Clean PSV spark spread Capacity/demand evolution Until the end of 27, large volumes of flexible hydro or higher priced thermal plant was required at peak But falling demand, rising renewable and CCGT capacity mean flexible hydro has to undercut CCGT to get scheduled Falling CCGT area below the average demand line indicates falling CCGT load factor Mothballing and closure of hybrid/ fuel oil has little effect Availability adjusted capacity by type and average and peak demand from Jan 6 (MW) GT Steam turbine fuel oil Steam Turbine gas GT/Conventional plant hybrid Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Average demand Peak demand Despite new renewables, improved demand and CCGT closures have tightened the market a little in the last 2/3 years

11 Clean PSV spark spread Spot clean PSV spark spread /MWh Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal 18* 6.1 * Jan/Feb Offer strategies have prevented the spark spread from staying negative for extended periods Clean PSV Spark Spread CO2 Fuel Italy spot But why such a big rebound since 214?

12 Clean PSV spark spread Economic coal/gas flip is starting to happen in Italy Coal, CCGT plant costs and switching price v market( /MWh) Italian CCGT has fallen to Italian coal generation cost frequently since summer 216 But German and Dutch coal and gas variable costs are around 4 /MWh lower (additional transport costs to Italian market) But lower efficiency of older Dutch CCGT has led to less switching Convergence of gas and coal costs reduces or eliminates CCGT losses on dip to coal/imports at the margin Abigger differential between Italy CCGT and coal prices could flip import to exports Italy coal variable cost CCGT variable cost Gas switch price PSV

13 Clean PSV spark spread Brindisi essential unit status and sequestration Generators found to have gamed the dispatch market in 216 were deemed essential units from 217 paid a capacity fee but forced to offer at variable cost Only Enel s 2.6 GW Brindisi coal plant was named but Brindisi and EPH s Fiume Santo plants were added to the essential units list Enel s Brindisi DA market offers went up from around 4 euro to 5 euro perhaps reflecting inclusion of dispatch costs in the Essential units methodology In September 217, the plant was sequestered on allegations that ashes from the plant sold for cement production were contaminated, breaching waste regulations The ruling gave Enel provisional operational rights but required disposal of ashes as hazardous waste leading to a further increase in offer prices to around 7 euro Brindisi unit offer prices v GeEO Italian coal plant variable cost estimate ( /MWh) 27-Sep 5-Oct 18-Oct 2-Nov Standard Unit 1 Unit 2 Unit 3 Unit 4

14 Clean PSV spark spread Hydro 214 was ten year high, 217 the low Seasonality of hydro production comes from storage of winter precipitation as snow, mainly in the Alps and therefore in the power market Nord zone Daily average constrained hydro production (Terna RoR + minimum hourly overnight flow of large scale hydro) in GW: low high % 7% 65% 6% 55% 5% 45% 4% 35% 3% Average total hydro production in MW: Min Max Italian hydroelectric reservoir levels as percentage of maximum on the first day of the month: Snow melt fills the reservoirs too High Avg Low V low Max Min

15 Clean PSV spark spread French nuclear production Average daily French nuclear and coal output (in GW) winter 15/16 v 16/17 v 17/18 French market balance Q416 and Q417 (MW) Renewable Nuclear Coal Gas Flex Net Fuel oil Demand hydro export Q Q /16 nuclear 216/17 nuclear 217/18 nuclear Coal 215/16 Coal 216/17 Coal 217/18

16 Clean PSV spark spread Supply/demand evolution 8, 7, 6, 5, 4, 3, 2, 1, - Average availability adjusted capacity by type and average and peak demand (MW) GT Steam turbine fuel oil GT/Conventional plant hybrid Steam Turbine gas Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Peak demand Average demand 8, 7, 6, 5, 4, 3, 2, 1, - Actual availability adjusted capacity by type and average and peak demand (MW) GT Steam turbine fuel oil GT/Conventional plant hybrid Steam Turbine gas Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Peak demand Average demand If we substitute actual monthly average solar, wind, constrained hydro and imports, and model Brindisi as steam turbine gas peaking plant from November, we can clearly see market tightening

17 Clean PSV spark spread Market tightness We can think of Italian market tightness in terms of how much thermal capacity is needed to meet demand in addition to renewables and imports More imports were partly offset by higher demand and less hydro this winter Correlation of clean PSV spark spread and call on thermal capacity Year on year change in call on thermal capacity (GW) Italy got France s extra export and also more from Switzerland this winter Demand Import Hydro Wind Solar Clean PSV spark spread ( /MWh) y = x R² = Average need for thermal capacity (GW) Clean PSV Spark spread ( /MWh) -1. Call on thermal capacity (GW)

18 Power Balance of Cal We have lots of snow Start of month Snow Water Equivalent ( SWE ) reserves in Lombardy, Piemonte and Veneto (million of cm) We have above average snow but ground water is low and evaporation v melt is not constant - assume balance of year hydro improves to average of average low 1 218

19 Power Balance of Cal 18 French nuclear still risk for Q418? ASN has asked EdF to examine and report on the manufacturing files of components manufactured at Creusot Forge foundry in all of its 58 reactors Only 12 have been done so far, most of the remaining 46 will close for refuelling over the summer EdF annual production forecast is close to the four year average, so looks like some delays are anticipated due to several 1 year inspections scheduled Average daily nuclear output (in GW) 215/16 nuclear 216/17 nuclear 217/18 nuclear Coal 215/16 Coal 216/17 Coal 217/18 Annual nuclear output (in TWh) Annual production EdF Forecast So assume imports at average of last 4 years?

20 Power Balance of Cal 18 BoCal 18 Demand: Cal 17 was highest of last 4 years but partly on hot June and August, so we have taken mid between Cal 17 and 4 year average Wind and solar: to reflect increasing capacity we have increased 4 year production average by ratio of 217 to 4 year average installed capacity Year on year change in call on thermal capacity (GW) Forecast Demand Import Hydro Wind Solar Less need for thermal capacity due to hydro, demand in June and August and import in November

21 Power Balance of Cal 18 Balance of 218 curve v 217 v model Curve prices on 15 March 218 ( /MWh) Market has already priced in an increase in hydro output Use of 2 year correlation (less coal) takes us 1.5 euro higher 1% increase to Cal 17 level demand takes us.5 euro higher Italia It/Fr It/Ger Clean SS PSV CSS Cal 17 YoY Model v model Apr Mag Giu Q Q Sum Q April CSS outturn -.22 /MWh Clean PSV spark spreads in /MWh. 2-Oct 2-Nov 2-Dec 2-Jan 2-Feb 2-Mar Q418 S18

22 Gas Summer 18 Demand European storage inventory at lowest level in recent years in percentage terms Italy Stogit mmcm: Previous Min Previous Max SY16 To get back to 1 Oct 17 inventory, summer demand for injection will be around 7 bcm more than last year Italy will be about.9 bcm higher and targets will also increase a little with extra 15 mmcm of capacity So Italian summer demand Δ: Power Industrial Storage Total bcm +.2 bcm +1. bcm -.1 bcm 2-2 1% 8% 6% 4% 2% % Total Europe SY17 SY12 SY13 SY14 SY15 SY16 SY17

23 Gas Summer 18 LNG supply for Europe/Italy? Europe has become briefly competitive with NE Asia LNG during March price spikes Futures markets show North Asia netback falling to around TTF level over summer Extra LNG above 7 bcm additional storage requirement, would be balanced by other supply reduction or increasing demand? It would have to be from the coal/gas flip in the power sector Recent spot and curve values in /MWh Estimated marginal cost of US LNG to TTF Zero floor price in spot auctions would make Italy the preferred European destination and PSV looks competitive with Asian netback so 1 bcm of ILNGS in S17 supply may be replaced with spot cargoes under new regime? May 14 OLT slot booked TTF North East Asia LNG less transport premium over TTF from US Gulf Estimated long term Asian LNG contract:gr4 3 month lag less transport premium TTF coal switch price

24 Gas Summer 18 Long term contract supply for Italy Tarvsio supply was flat Oct-Mar so same ToP flow over summer? Despite short term capacity bookings and reports of new production coming on line, Algerian supply over winter was very similar to GY16 at around 7 mmcm/d so if annual contract volumes are unchanged, we would expect similar supply this year But there could be upside if new production gives excess volumes to export? So Italian summer supply Δ: Russia Algeria LNG Net flat possible increase possible decrease flat? Summer Average daily supply (mmcm/d) Mazara del Vallo Tarvisio Passo Gries Gela LNG National Production GY17 entry capacity bookings at Mazara del Vallo (mmcm/g) Sum-13 Sum-14 Sum-15 Sum-16 Sum-17 Monthly booking Quarterly booking Annual booking Long term booking

25 Gas outlook Summer 18 Market imports Liquidity corridor implementation unlikely given political situation Same supply demand means same requirement at Passo Gries German exit capacity at Wallbach continues to be reduced to 3 mmcm/d So PSV premium will need to rise to French import level ~ TTF + 3 euro when more than 3 mmcm/d less Swiss demand (about 4 mmcm/d in summer?) is needed PSV/ PSV/ PSV/ PSV/ PSV GR7 TTF NCG VTP Sum April PSV/TTF outturn 2.2 /MWh Summer Average daily supply (mmcm/d) and PSV premium over neighbours in /MWh Mazara del Vallo Tarvisio Passo Gries PSV/TTF spread in /MWh Transitgas flow in mmcm Sum Sum Sum Sum Sum Gela LNG National Production Sum-13 Sum-14 Sum-15 Sum-16 Sum-17 German exit capacity at Wallbach mmcm/d

26 Gas outlook Summer 18 Summer 217 If there is insufficient supply surplus to enable injections at required rate, injector buying interest pushes spot price up to the marginal injection price If surplus is more than maximum injection, prices fall until production reduces or demand increases Many storage facilities with different characteristics and many injectors with different inventory so many different marginal injection prices! Jul 2-Aug 2-Sep 2-Oct High drawdown in winter 16/17 pushed back fill date and hence pushed up marginal price Daily PSV price Injection volume

27 Gas outlook Summer 18 Summer 17 spot prices Mostly, there was insufficient supply surplus to get to maximum/ target injection levels, so prices mostly at marginal injection price TTF around the October price PSV prices were mostly above October and sometimes even above Q1 as capacity holders sought to avoid.4 /MWh penalty for not meeting minimum end of month inventory levels Bullish summer 17 spot prices had little impact on winter until August bearish sentiment on expected LNG arrivals? Weekday DA v implied October price ( /MWh) With lower inventory this scenario is likely to be repeated across Europe if overall supply scenario is unchanged PSV spot PSV Oct TTF spot TTF Oct

28 Power outlook Demand scenarios Terna base scenario from 216 strategy returns to modest.3% growth High scenario growth.9% - increasing electrical intensity due to progressive tariffs or EV? corresponds to base scenario of SEN Alba scenarios: low at.3%, high at 2% Annual power demand (TWh On low scenario, average demand rises by about 1 MW pa Terna high/sen gives 3 MW pa Alba high scenario gives 75 MW pa increase Actual Terna base May 217 Terna high May 217 Alba high Alba low

29 Power outlook 9 8 Approved renewables to start Capacities accepted for incentives expected to commence operation over next three years by regime (MW): Annual installations expected Wind 417 Hydro 3 Geothermal 33 Biomass Wind Hydro Geothermal Biomass

30 Power outlook SEN targets 55% renewable in power by 23 Carlo Calenda started the process for the next renewable incentives decree on last day in office Technology neutral so includes PV? and aiming at >2 GW pa of incentives to be awarded % of consumption Italy Power Power target Heating Heating target Transport Transport target

31 Power outlook SEN target installation rates incentives will lead to installations from 22 SEN production forecast shows wind, solar, hydro growth and biomass drop to meet 55% renewables which implies Annual average installations from of: 3.7 GW PV 1.2 GW wind 15 MW hydro -11 MW biomass Assumption of how much nonincentivised PV? Power production mix RES (SEN) Hydro Wind PV Other RES Natural gas Coal Other fossils

32 Power outlook SEN coal phase out

33 Power outlook Montenegro & France interconnectors in 219 France and Montenegro 1 st line should both be completed in 219 Construction & operation contracts for private section of IT-FR IC signed in July 217 Only 1 of 2 IT Montenegro lines to be complete by 219 other expected in 226 There are lots of other projects being proposed or under study but none seem very likely before 225 despite more aggressive target dates for PCI projects

34 Power outlook Capacity forecast To end 225: Coal phase out Adding 3.4 GW of open cycle GT (or reciprocating engine) from capacity market No change in CCGT availability Completion of French and Montenegro interconnectors in January 219 Renewables - installation of capacity awarded incentives in 218/219 and PV at 4 MW Availability adjusted capacity forecast to end of 225 by type (MW) renewables as per SEN Capacity (MW) GT Steam turbine fuel oil Steam Turbine gas GT/Conventional plant hybrid Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Load Factor Adjusted MW pa PV % 52 Wind farm % 31 Biomass % -59 Hydro run of river % 72 Geothermal 85% Demand

35 Power outlook Base demand scenario (MW) GT Steam turbine fuel oil GT/Conventional plant hybrid Steam Turbine gas Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Peak demand Average demand Additional import and renewable loosen market in then balance falling coal capacity, new GT adds margin faster than demand growth

36 Power outlook 9 SEN/Terna high demand scenario (MW) GT 8 Steam turbine fuel oil GT/Conventional plant hybrid 7 Steam Turbine gas Hydro Reservoir Hydro Pumped Storage CCGT Import Steam turbine coal Hydro run of river Biomass Wind farm Photovoltaic Geothermal Peak demand Average demand Market tightens as demand pushes above CCGT more often

37 Power outlook Conclusions - Power Cal 18 backwardation on expected improvement in French nuclear availability and hydro Cal 19/2 backwardation driven by new interconnectors SEN target renewable installation rate would allow phase out of coal without overall tightening Flexibility from storage will help smooth out diurnal profile in summer But winter peaks on calm, cloudy days? Italia It/Fr It/Ger Clean SS PSV Cal Cal Average spot clean PSV spark spread /MWh Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal Cal

38 Gas outlook Coal/gas flip is beginning to happen in Italy CCGT avoidable cost already lower than less efficient coal at times, Enel offer behaviour GY16 coal 12 TWh below average implies 2 bcm more gas demand All year flip of all capacity would give an increase in gas consumption of about 2 bcm But it will not be digital 214 was a normal year for gas burn before flip 215 was low hydro, 216 low hydro, low import and start of flip Spot fuel, CO 2 allowance and other variable operating costs of CCGT and coal plants in /MWh Italy coal CCGT switch price Power Gas burn CCGT TWhe TWhg bcm Load factor 214 gas generation % Add 214 coal generation % Add 214 imports % Exports at 2 GW % Potential CCGT % Maximum CCGT % PSV 38

39 Gas outlook Demand scenarios Base scenario is Terna demand, renewables as SEN target, coal phase out CCGT output is squeezed by new interconnectors in 219 then higher renewable installation until assumed coal closures Alba flip assumes full switching of coal and imports flip to export plus Snam transport upside Annual gas consumption in bcm Alba flip assumes continued partial switching increasing to full flip by 222 due to stability mechanism Actual Feb 29 SRG forecast 217 SRG low 217 SRG high Alba base Alba flip We will use the extremes Alba base and Alba flip to look at supply/demand scenarios

40 Gas outlook Long Term ToP from Algeria, Libya, TAP, LNG including outages and ToP adjustments ToP assumed at 9% of Libyan and TAP capacity, 6.4 bcm at ALNG/Rovigo Algeria ToP forecast based on current supply TAG and Transitgas included at 1% of annual supply capacity There is still ample margin without Algerian renewal in low demand scenario Annualised ToP plus northern supply capacity and demand in (bcm) - existing and committed infrastructure 1 Transitgas Contract issues: 219 Ukraine and Tunisian transit expiry TAG Back up LNG TAP Rovigo Transmed Panigaglia Greenstream Gorizia Production Alba low power/high renewables Alba flip

41 Gas outlook Algerian renewal at 2 bcm pa, biomethane production revival In low demand scenario, TAP supply arrives as demand depressed by new power interconnectors and increasing renewables installations but we still need significant supply from the North High demand scenario would maintain market balance at around recent levels Annualised supply capacity and demand (bcm) - Existing and committed infrastructure 12 Transitgas TAG Back up LNG TAP Rovigo Transmed Panigaglia Greenstream Gorizia Production Alba low power/high renewables Alba low power/high renewables

42 Gas outlook Conclusions - Gas General European market backwardation on backwardation of oil and coal prices, expectations of more LNG No risk premium for Cal 2 from CO 2 pricing, Ukraine and Tunisia transit uncertainties low probability, huge impact events? But more chance of brinkmanship to spook markets? Cal 2 PSV/TTF spread backwardation was logical on completion of TENP repairs increasing Wallbach exit no expectation that Liquidity corridor will be introduced but now TENP outage extended? Coal phase out can be accommodated without significant impact on gas demand if renewables installations increase to SEN target levels from 221 PSV PSV/ GR7 PSV/ TTF PSV/ NCG PSV/ VTP Cal Cal