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 30th
September 2010 by its final
provisional form. The revised market design, which is termed as the 5th
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.
[1]
Regarding the
balancing mechanism, it should be noted that market participants do not
submit
bids and offers for deviations from their day-ahead schedules, so as to
formulate the imbalance prices, as is the case with the balancing
mechanisms of other countries. Instead, the imbalance price is derived
by
re-solving the same cost-minimisation algorithm as in the day-ahead
market, by
inserting the actual values of the various inputs (demand, renewables
output,
plant availability), instead of day-ahead predictions.
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.
[2] The Ηeron OCGT unit, previously
contracted with the TSO for the provision of ancillary services,
retained over a fourth year a
long-term capacity availability contract with the incumbent, PPC. As
noted by
Heron, this contract, similar to a tolling arrangement, increased its
limited
hours of operation, hence reducing gas transportation charges. During
the June
strike, this plant operated quite intensively and the same occurred in
the gas
crisis in February 2012.