Wholesale market

1. Current Market Design
2. Recent Developments
3. Future Challenges
4. Market Volume
5. Price Dynamics
6. Fuel Shares
7. Market Structure



























1. Current Market Design

The Greek wholesale electricity market has been organised as a pure mandatory pool since its inception in 2005. After gradual refinements, a transitional market design, implemented over a five-year period, was substituted on 30^th September 2010 by its final provisional form. The revised market design, which is termed as the 5^th Reference Day, reflects the full implementation of the 2005 Grid and Market Operation Code.

In essence, the new market design introduced a distinction between the day-ahead market and the balancing mechanism that follows, as in other countries with compulsory pools. This structure reflects with more clarity the factors influencing prices, the uncertainties involved and the implied risks at these distinct time scales. More specifically, during the transitory market regime, the Day Ahead market provided an indicative unit commitment schedule and a reference spot price (SMP forecast), which served purely as a signal. Cash-flows were based on ex-post SMP prices. These were derived by re-solving the same cost-minimisation algorithm as in the day-ahead schedule by inserting metered values of the various inputs (mainly demand, plant availabilities and renewables’ output) instead of day-ahead forecasts. These ex-post prices were applied to the actual quantities consumed or produced (the latter reflecting to a large extent the real-time dispatch orders of the TSO).

As opposed to an overall market settlement (through ex-post SMP prices), the current market design involves two distinct settlement processes:

• The settlement of the day-ahead market, in which generators’ payments (suppliers’ charges) are computed, based on the SMP prices and the plant schedules derived from the day-ahead dispatch (load declarations submitted).
• The settlement of imbalances^[1], in which deviations from day-ahead schedules are charged or compensated, depending on whether they are exogeneous or reflect the TSO’ dispatch orders.
• There is also a provision for imbalance penalties, if certain limits are violated regarding the magnitude and the frequency of the deviations.

In the day-ahead market, uniform pricing still applies, reflecting the offer of the most expensive unit dispatched so that predicted demand is satisfied. Zonal pricing, intended to reveal congestion problems and signal the location of new capacity, has not been activated yet, although two zonal prices, applicable to generators, are explicitly derived, currently only as an indication. Participants may enter into bilateral financial contracts (CfDs), but physical delivery transactions are constrained within the pool and related contracts do not exist. A cap of 150 €/MWh has been imposed on generators’ offers.

The following rules or supplementary mechanisms still apply:

• A lower limit is imposed on generators’ offers, equal to the minimum variable cost of each unit in each trading period, as -in the current structure- the incumbent has a strong incentive to suppress wholesale prices.
• A cost-recovery mechanism ensures that generators dispatched by the TSO, beyond the day-ahead schedule, are remunerated based on their declared minimum variable costs plus a 10% margin. This mechanism creates a safety net, which often makes participants rather indifferent to the price levels.
• A Capacity Adequacy Mechanism is applied for the partial recovery of capital costs, with suppliers being obliged to buy capacity certificates from generators. The value of these certificates was revised in November 2010 from 35.000 to 45.000 €/MW, in order to alleviate the impact of low demand on generators’ revenues. Adjusting the value of the certificates based on the technical flexibility and environmental impact of each plant was also explored as a possible future refinement.

2. Recent Developments

From February 2012 onwards, an ITO model (as opposed to an ISO) was adopted for the Greek market and this implied the re-structuring of the former TSO into two discrete entities:

• The Market Operator (LAGIE), which solves the day-ahead market, conducts its clearing, and engages into contracts with renewable producers.
• The System Operator (ADMIE), which owns the network, as a subsidiary of PPC, conducts the real time dispatch, the clearing of the imbalance market and the settlement of all other charges or payments.

Given the above development, the market code was decomposed into the Grid Code and the Transactions Code (Code documents on Greek). 

RAE determined the principles for the certification of the new ITO in accordance with the Law 4001, which reflected the EC directive. The TSO’s certification process is expected to be completed by the end of 2012. A Distribution Network Operator was also formed and RAE is currently assessing its compliance procedure.

3. Future Challenges

Since the initiation of the deregulation process in 2000, the market design has evolved, not independently of the underlying market structure, but in response to its asymmetries or inefficiencies, intending to alleviate the distortions arising from structural features. In 2011, the market got more mature, in the sense that substantial new capacity had entered the system, intensifying competition for medium and peak demand. Still, severe liquidity problems and credit risks started to emerge in the energy sector, partially reflecting the economic recession but also the effects of policies regarding retail and renewables tariffs. The implemented policies had been appealing to governments in the context of social policy and renewables growth respectively, but interpreted as revenue streams, they were internally inconsistent. Costs were not correctly reflected or adequately transferred across the value chain, creating sustained debts in the renewables account, managed by the TSO, and diminishing gradually its liquidity.  Two other political choices applied in 2011, the introduction of a tax levy on natural gas and of a property tax on the electricity bill, created adverse effects on competition and consumers’ payments respectively. Debt issues, which were expected to escalate in 2012, raised unprecedented challenges for the market participants, the TSO and the regulator. This explosive situation stimulated the exploration of alternative ways to move forward and is likely to initiate structural reforms in the coming years, consistently with the need for market adjustment to the internal market paradigm envisaged for 2015.

More specifically, the Greek wholesale electricity market has been organised as a pure mandatory pool since its inception in 2005, so to as to allow competition to emerge in a context with a severe constraint: no structural reforms were implemented on PPC, the previous monopolist, such as plant divestures or consumers release, as elsewhere in Europe. In particular, the incumbent remained dominant in both generation and retail sectors, retaining exclusive access to cheap lignite and hydro resources, while retail prices, despite the gradual removal of cross-subsidies, remained not linked to wholesale costs. This combination of market features posed severe obstacles to new entry in early years of market liberalisation, signifying capacity shortage over the following years. The capacity certificates introduced in 2006 created incentives for new investment, which turned out to be adequate, as almost 2000 MW of new, IPP gas capacity were added to the system by the end of 2011. Still, projections for strong and prolonged demand growth (around 2.5% at the annual level) were disrupted in 2009, when demand sank by 7% due to the erupting economic crisis, and has not recovered since then. Hence, a substantial capacity surplus has emerged, with limited export possibilities and limited cost-reduction flexibility. In addition to diminished demand levels, the increasing renewables penetration steadily curtails gas generation to an extent that may even expose them to the take-or-pay penalties implicit in their gas supply contracts.

Furthermore, wholesale prices remain low, not reflective of the full energy production cost. Their levels are suppressed due to significant amounts of compulsory quantities, including mandatory hydro, plants’ minimum operational levels, and renewables, which currently constitute a fast escalating component. The deviation between the depressed wholesale levels and the high feed-in-tariffs applied for renewables reimbursement has created a sustained (not temporal but structural) debt in the renewables account, managed by the TSO, which reduces its liquidity and hence, its ability to pay conventional generators and importers over 2012. Simultaneously, consumers’ debt (unpaid electricity bills) escalated to 1.4 billion (estimated value) at the end of 2011 due to the severe economic recession and the incorporation of a property tax into the electricity bill, which magnified its amount. This convolution of adverse conditions and inconsistent policies has raised severe financial problems for market participants and the TSO, which started to become more evident in 2011 and escalated over 2012.

In this challenging environment, RAE is assessing a restructuring of the market design, so as to reduce costs, enhance competition across the value chain, as well as compatibility with the European target model.

4. Market Volume

The day-ahead market yields the reference price for the industry, as it constitutes the major component on which generators’ cash-flows are based. Due to the mandatory physical trading in this market, the traded volume of electricity is equal to the annual demand (including the interconnection balance), i.e. 51,872,288 MWh. This represents a decline of 0.94% relatively to 2010. Alternatively, we may consider imports and exports as distinct trading volumes in the market and add them to the local plant production.  Adopting the latter definition, the yearly trading volume attains the value of 59.766.618, which represents an increase of 3% relatively to 2010. A futures market has not been developed yet, while OTC trading has not been activated either.




5. Price Dynamics

As opposed to collapsing price levels in the previous two years, wholesale prices reverted to higher levels in 2011, displaying an average value of 59.36 €/MWh  and hence a robust rise of 13.5% relatively to the price average in 2010 (52.30 €/MWh). This price reversal was not a sign of economic recovery, but reflected to some extent the impact of market fundamentals, and mainly the scarcity of hydro after two successive years of intense wet conditions. While water scarcity exerts an upward pressure on wholesale prices, due to the need for substitution by more expensive energy, this effect was less substantial than in previous years due to the substantial capacity surplus in the market.

Furthermore, the price rise was an implication of the new tax levy imposed on natural gas from 1^st September 2011 onwards. This controversial tax, which raised concerns about its asymmetric impact on gas production vs. lignite and imports, implied an increment of 5.4€/MWh (th) in the variable cost of the gas plants (assuming maximum plant efficiency). The effect of this tax counteracted the downward trend in prices that the seasonal decline of demand would be expected to induce in certain months (e.g. October) and combined with the shrinkage of hydro production, yielded a sustainable price increase from September onwards. Indicatively, the daily average price increased from 55.66 €/MWh on 31th August to 73.09 €/MWh on 1 September (+31%), although the market fundamentals remained quite similar. At an aggregate level, the average price level escalated from 54.60 €/MWh prior to the tax levy to 68.83 €/MWh in the period after, while the average price in 2010 was 52.30 €/MWh. This tax was modified in January 2012, so as not to be incorporated into generators’ offers in the electricity market, but still, it had an adverse effect on industrial and export activity, diminishing the competitiveness of Greek products.

Price volatility in 2011 increased quite substantially. Prices exhibited a standard deviation of 23.18 €/MWh (19.55 €/MWh in 2010), reaching a maximum value of 150 €/MWh (price cap) in 14 hourly trading periods and a minimum of 0 in 35 periods, while in 5% of the trading hours, they exceeded 100 €/MWh. Zero levels occur during demand troughs (typically the Easter break in April), in which cases compulsory quantities (minimum plant generation, renewables and imports) may exceed consumption. Due to this surplus, imports, offered at a zero value, may get curtailed, setting the price to its minimum level. It is notable that this extreme case occurred only a single time in 2009, which reflects the increasing penetration of wind generation.

Figures 1and 2  display the dynamics of the day-ahead price, SMP, across the year, as well as its intra-day profile. Given the market design change introduced in September 2010, this price is the relevant market index, as it determines the largest part of participants’ cash-flows.

The intra-yearly evolution of prices reflects the seasonal variation of the constrained hydro releases (diminished levels overall, but increased from June to August, with a peak-shaving objective), the dynamics of gas prices, maintenance schedules and outages. In particular, severe outages occurred in two gas plants towards the end of the year (Protergia, an IPP unit, and PPC’s Lavrio 5), rendering them unavailable over long periods (two and six months respectively). In the end of June, a labour union strike at PPC, causing major capacity withholding (up to 20 plants), resulted in escalating prices (up to 108 €/MWh) over nine days. It was also notable that in November, demand increased by 8% relatively to November 2010. It seems that air-conditioning was used extensively for heating purposes as a substitute to heating oil, since the latter was perceived as a more expensive option. A secondary factor, which induced some price volatility over 2011, was the trial operation periods of new plants. These induced occasionally output variations from 300 to 4400 ΜWh on a daily basis. According to the market rules, this output entered the market as must-run generation, hence counteracting some of the upward pressure on prices, depending on the combination of other parameters.

 Figure 1 SMP dynamics (actual and smoothed levels) over 2011

Figure 2. SMP volatility (st. deviation) over 2011




6. Fuel Shares

A critical factor in understanding the allocation of fuel shares in the Greek market is the level of hydro production, which reflects both stochastic elements (due to uncertain water inflows) and the management approach implemented by PPC.  After two successive years of adequate or even, excessive water inflows, which had resulted in an escalation of hydro production, 2011 was anticipated to be a dry year, a prediction which was actually verified. This expectation was consistent with the typical alternation pattern of wet and dry periods, even though the duration of the water cycles exhibits some variability, possibly due to climate change effects.

Overall, hydro production in 2011 shrank by 45% relatively to 2010. This was consistent with limited water inflows, which dropped to 2721 GWh, exceeding only by 13% the worse-case (driest) scenario predicted at the end of 2010. In particular, the low inflows in Q1 2011, depressed by 57% relatively to Q1 2010, raised significant concerns. In response to them, PPC implemented a conservative water management approach, which could be interpreted, ex-post, as over-restrictive in certain time periods, but counter-acted well the scarcity that emerged in Q4. More specifically, over the period January to September 2011, the total reservoir level exceeded its expected value, even under the best (wet) scenario, allowing for mixed interpretations. Subsequently, however, the reservoir level dropped to levels below the worse-case scenario, reaching at the end of the year a value of 1547 GWh, as opposed to the range 1623-1895 GWh forecasted one year ago. Water inflows from September to December were very limited, as opposed to their annual pattern. Indicatively, November inflows diminished to 50 GWh, as opposed to the year-ahead expectation of 196-369 GWh and 689 GWh in November 2010.

Simultaneously, mandatory waters dropped below the dry-scenario prediction by 28%, which partially reflects the reduction of over-flooding risk. The reduction of mandatory hydro increased the competitive part of the supply curve, creating more space for gas generation.

Overall, local generation increased by 4.2% relatively to 2010, reversing the previous year’s downward trend (-3.7%), with demand remaining almost stable (minor decline of -0.9%). Lignite production remained stable, with a minor increase of 0.5%, as no decommissioning occurred over 2011. Due to its base-load nature, lignite production followed closely the demand fluctuations, peaking in July, August and the winter period (November up to February).  Oil generation shrank substantially, by 93%, in line with the previous two years’ trend, being substituted by the more economic gas, increasingly penetrating the market. Gas production exhibited an increase of 43.3% (relatively to 10.7% in 2010), hence partly counteracting the hydro decline.

Renewable generation connected to high-voltage, which mainly involves wind parks, peaked over the months January to April, August and December, a pattern which is rather typical of wind dynamics. Renewable production increased substantially, by 24.3%, but its market share remained still low.  Imports declined by 16%, as the price spread with northern countries showed signs of reduction, and quantities were reallocated across interconnected countries, since the interconnection with Turkey became operational. Exports increased by 40%, and this mainly reflects substantial exports to Albania, given its hydro scarcity, which caused severe energy shortage in this country. The prolonged drought caused an escalation of exports to Albania to 2.1 TWh, a level which represents 54% of total exports from Greece. Exports to Italy got reduced by 26% (1.7 TWh), being adjusted to the higher volatility and the moderate decline in spreads, the magnitude of which remained still attractive.

Figure 4 presents the allocation of production across the various technologies, as well as net imports at the monthly level, while Figure 5 displays the annual market shares across fuel and net imports. Both figures refer to the interconnected system, to which the wholesale market relates. If the production on the non-interconnected islands is taken into account, the oil share would rise significantly (see Section 5).

 

Figure 3. Production Allocation across Fuels and Net Imports at monthly level

 

Figure 4. Annual shares of fuels and net imports

 

7. Market Structure

Regarding the market structure, PPC retained its dominant position over 2011 but its market share declined substantially, both in the generation and the supply side. In the generation sector, a significant change towards a less concentrated structure occurred in 2010, as two new IPP units entered into commercial operation, and this change was reinforced in 2011, with the addition of two other IPP plants.  In terms of thermal capacity, this direction of market evolution is not expected to persist in the future, as all private plants have now been completed, and the new plants expected are owned by PPC. This would change however, if plant divestments, intensively discussed under Troika’s pressure or alternative measures of PPC’s capacity allocation are implemented in the coming years. Apart from conventional generation, changes in market structure were enhanced by a steady, currently explosive, renewables’ penetration, in which PPC’s share is minor.

More specifically, regarding new capacity, significant additions occurred in 2011, intensifying competition for mid and peak load. The market dynamics changed as a result, but only to the extent that the details of the market design allowed. A critical factor for market outcomes was the market rule that allows generators to offer 30% of their plant’s capacity at a price below its minimum marginal cost. This rule allows the dispatch of various plants for reserve provision, which is crucial for the plants’ viability in an era of capacity surplus, but suppresses prices to levels not reflective of the full production cost. In this context, RAE has proposed the removal of this rule, which turned out to be rather distorting. Focusing again on market structure features, after the entry of two new CCGT plants (Elpedison Thisvi and Heron CC) in April 2010, two additional plants, Protergia (444.5 MW) and Korinthos Power (437 MW), entered the system in 2011. The former initiated its commercial operation in December 2011, after trial operation since January 2011. The latter started its trial operation in December 2011, with commercial operation expected in April 2012. Both plants belong to the Mytilinaios Group. In particular, Korinthos Power is a subsidiary company of Mytilinaios Group, owned jointly with Motor-oil, with shares 65% and 35% respectively. Given the above developments, Mytilinaios Group became the largest IPP player in terms of installed capacity, followed by Elpedison with capacity of 812 MW.

Given the above developments, (8) IPP gas plants are currently active in the wholesale market. Their ownership structure is delineated below:

• Enthess (395 MW) and Thisvi (422 MW), both CCGT plants, are owned by Elpedison.
• Heron II (432 MW, CCGT) and Heron I^[2] (147.5 MW, OCGT) are owned by Heron Thermoelectric (GEK Terna- Gdf Suez).
• Protergia (444.5 MW, CCGT), Korinthos Power (437 MW, CCGT), and Alouminion (334 MW, large-scale CHP) are owned by Mytilinaios Group.
• Motoroil is a cogeneration unit of 2 MW net capacity, owned by the refinery.

Moreover, as stated by the TSO in its ten-year Grid Development Plan, six other thermal units, of total capacity 2476 MW, had also applied for connection until December 2011. This capacity amount included the incumbent’s new CCGT units and more specifically, Aliveri V (417MW), projected to be completed by Autumn 2012, and Megalopoli V (811MW), which seemed to be progressing in terms of the expansion of the gas network in the region. The above capacity amount does not include however, Ptolemaida V (660 MW), for which private involvement along with PPC has been discussed. In addition, five hydro units, of total capacity 335 MW, had applied for connection by the end of 2011, while other 287 MW got licensed, but not applied for connection yet (including Mesochora). The obsolete lignite units Megalopoli I and II, of capacity 250 MW, were decommissioned.

Despite the substantial amount of capacity that had applied for connection in the past, the TSO estimated that due to the economic recession, various investment plans were cancelled, which seems a reasonable assessment. In particular, the units expected to be added to the system over the next decade, which were used for system analysis, are Aliveri V, Megalopoli V, Ptolemaida V and Ilarion (a 153 hydro unit in Aliakmonas river).

Electricity demand remained fairly stable over 2011 at 51872 GWh, exhibiting a minor decline of  0.94% relatively to 2010  at the interconnected system. At the national level, demand was also unaffected, amounting to 61834 GWh (relatively to 61817 GWh in 2010). It is notable that demand recovered over the last quarter, exhibiting an increase of 2% relatively to Q4 2010, as air-conditioning was used quite intensively for heating, perceived by consumers as a less expensive option than oil.

Given the addition of substantial capacity over two consecutive years, the market share of PPC declined significantly in 2011. In the interconnected system, PPC’s share, in terms of volume, dropped to 75% of local production, relatively to 85% in 2010, while independent gas producers achieved a share of 20% (Elpedison 8.9%, Mytilinaios 5.6% and Heron Thermoelectric 5.3%). Renewables captured 5.2% of local production. While IPP’s share more than doubled, PPC’s gas production declined by 816 GWh (13.5%). It is interesting that despite this decline, the gas cost for PPC increased by €10 million due to an increase in gas prices of 18.4% and a €21 million tax contribution due to the levy imposed on gas.

At the national level (including non-connected islands), PPC’s production covered 70.1% of total demand in 2010, with the corresponding share being 77.3 % and 85.6% in the previous two years. Subsequently, this market share was suppressed further, reaching 67.5% in Q1 2012. In absolute terms, PPC’s production plus import activity was reduced by 4451 GWh, while in 2010 this quantity had already been reduced by 5123 GWh. The import activity of PPC was also reduced, by 18%. Regarding renewables generation, PPC’s production remained low (246 vs. 374 GWh), due to water scarcity affecting its small hydro units, by 192009while independent renewable production reached 3958 GWh. Wind parks connected to the high-voltage Grid yielded 2535 GWh.

The HHI index for the wholesale market in 2011 attained the value of 5764, dropping further from the value 6844 in 2010. It is notable that the index exhibited substantially higher values, close to the upper bound of 10000, in all previous years. This value indicates that the market is evolving towards a more competitive direction, with the current structural constraint being the lack of diversification for IPPs as well as the lack of physical hedge for them (consumers). As long as their fuel cost remains high and retail prices are not linked to wholesale, independent generators’ entry into the retail sector does not seem appealing.

The HHI index for the retail market in 2011 was substantially higher than the generation sector, attaining a value of 8497, and hence, improving only slightly from the value 8616 in 2010. Although suppliers in the past got attracted by high potential margins in certain customer categories, these margins ought to be reduced as regulated prices are being progressively corrected, removing cross-subsidies. In addition, retail margins turned out to be quite sensitive to the increase that wholesale prices registered in 2011, particularly towards the end of the year.

While thermal generation is saturated, given the demand recession, the renewables sector remains an attractive investment field, with the level of feed-in-tariffs being a major incentive, even if their levels are adjusted downward for new capacity. In addition, bureaucratic (licensing) obstacles are progressively simplified. Given the targeted level of wind penetration (7500 MW by 2020) and its intermittent nature, stand-by reserve as well as secondary reserve is expected to emerge as a significant component of financial returns for thermal plants. This reimbursement did not occur in 2011, as gas plants competed severely for reserve provision, in order to get dispatch and receive the cost-recovery payment, yielding reserve prices close to zero. Hence, ancillary prices are not independent of the supplementary mechanisms introduced in the market, and cannot be corrected if viewed in isolation.