Milder, lower-cost gas storage measures planned for winter

This winter season’s Preventive Action Plan for natural gas supply security in Greece is expected to be significantly lower in cost as it will be limited to a basic set of milder precautionary measures, energypress sources have informed.

The Preventive Action Plan will be determined by the outcome of a risk study currently being conducted for the upcoming winter, deputy energy minister Alexandra Sdoukou recently informed.

Though the study’s results are not yet out, it has already become apparent that drastic energy security measures such as those taken for last winter – among them the rental of an additional FSU at the Revythoussa LNG terminal just off Athens – will not be necessary, well-informed sources have contended.

This winter, gas grid operator DESFA, running the Revythoussa LNG terminal, does not intend to hire an additional FSU, which, along with gas-storage facility rentals abroad last winter season by electricity producers operating gas-fueled power stations in Greece, ended up costing 160 million euros.

In the lead-up to last winter, Greece’s gas-fueled electricity producers were required to store natural gas at underground storage units of other EU member states, as domestic gas storage facilities did not suffice to cover precautionary-measure needs.

The country’s electricity producers have, this autumn, remained far more subdued on gas-storage action at facilities in fellow EU member states. Some of Greece’s major electricity producers have reached agreements to use gas storage facilities, primarily in Italy, if needed, sources informed.

Gas amounts involved in these agreements are believed to be well below levels foreseen by EU regulations and RAAEY, the the Regulatory Authority for Waste, Energy and Water.

Last winter, RAAEY, aligning itself with EU Regulations, which require all member states to store gas amounts equivalent to 15 percent of national annual consumption, set a 7.5 TWh storage requirement.

Market officials have expressed concerns as to whether this requirement still needs to be maintained, noting the Revythoussa LNG terminal could cover extraordinary needs through additional LNG shipments.

Wholesale electricity prices up over past week

Wholesale electricity price levels rose over the past week, the average market clearing price rising by 4.76 percent compared to the previous week to 151.95 euros per MWh, with upper and lower levels reaching 218.35 and 80.16 euros per MWh, respectively.

The past week’s highest average market clearing price was recorded on March 2, reaching 160.60 euros per MWh.

During the same period, wholesale electricity price levels in other parts of Europe ranged from 136 to 195 euros per MWh, while prices yesterday ranged from 141 and 167 euros per MWh.

Electricity demand remained low, for this time of the year, while lower RES and hydropower unit output led to a slight increase in prices at the Hellenic Energy Exchange, according to an analysis by IENE, the Institute of Energy for Southeast Europe.

RES units averaged a daily output of 36 GWh for an energy-mix share of 29 percent over the past week, official data showed. RES output totaled 251 GWh for the week, an 11 percent reduction compared to a week earlier.

Hydropower facilities covered 2 percent of demand, injecting just 16 GWh into the grid, 14 percent less than a week earlier. Natural gas-fueled power stations generated 286 GWh over the past week, covering 33 percent of demand, while lignite-fired power stations produced 145 GWh to cover 17 percent of electricity demand.

Electricity demand remained virtually unchanged over the past week, at 897.131 MWh, compared to 897.306. It peaked at 138.128 MWh last Thursday, while the week’s low was recorded on February 27, at 107.471 MWh.

The low-voltage category, including households, represented 56 percent of electricity demand over the past week, the medium-voltage category represented 19 percent of demand, the high-voltage category, or energy-intensive industry, represented 17 percent, 5 percent concerned the Cretan grid, while electricity losses of 3 percent were also recorded.

Gas-fueled power stations output down, Italy imports up

The energy-mix share of gas-fueled power stations has contracted significantly as a result of the country’s rigid month-ahead pricing method used for natural gas, which prevented electricity producers from taking advantage of falling spot market prices throughout October. Gas prices remained fixed at higher price levels recorded at the end of September.

Given the circumstances, energy companies chose to shut off gas-fueled power stations in significant numbers. This resulted in a sharp increase of electricity imports from Italy, where, as is also the case in other European markets, the spot market greatly influences gas price levels.

Italy’s day-ahead electricity market was below that of Greece’s throughout October, ending the month at 211.63 euros per MWh, compared to 232.6 euros per MWh in Greece, Europe’s highest, despite a 44 percent drop from September.

Gas-fueled power stations in Greece ended up representing just 23 percent of the energy mix in October, well below usual levels of around 40 percent.

Ministry, power producers to discuss diesel as alternative

A leading energy ministry official has scheduled, for today, a teleconference with electricity producers operating gas-fueled power stations to discuss the prospect of emergency diesel supply for alternative generation purposes should natural gas imports encounter issues.

The energy ministry’s secretary-general Alexandra Sdoukou and producers will  overview the supply chain to be activated for diesel as an alternative liquid, if market conditions require such action.

Previous thoughts by officials for power stations to partially run on diesel fuel, a few hours per month, to help ease natural gas demand, appear to have been abandoned as producers have raised concerns about various complications.

Instead, diesel will only be used as an alternative fuel by gas-fueled power stations if gas imports reach perilously low levels and the country enters a period of heightened alert. RAE, the Regulatory Authority for Energy, will need to approve the switch by producers to diesel.

Five gas-fueled power stations in Greece are equipped to also run on diesel. Power utility PPC operates one of these in Lavrio and another in Komotini, Elpedison operates two more, in Thisvi and Thessaloniki, and Heron operates such a unit in Viotia.

Experts have previously informed energypress gas-fueled power stations can run on diesel for a maximum of five days per month without any technical issues or maintenance needs and 40 days a year. This limitation is necessary to avoid excessive soot accumulation and facility underperformance, the experts noted.

 

Power producer diesel reserves focus of emergency meeting

Top-ranked officials representing the country’s Hellenic Petroleum (ELPE) and Motor Oil refineries, electricity producers, as well as RAE, the Regulatory Authority for Energy, will take part in an emergency meeting called for today by the energy ministry to address diesel safety reserves and a conversion to this energy source by a number of natural gas-fueled power stations should Russia completely disrupt its gas supply.

According to a RAE plan, five natural gas-fueled power stations will run on diesel should Moscow turn off the taps. These facilities will need to maintain an adequate level of diesel reserves covering the emergency plan.

Diesel reserve level requirements for these power stations have been increased, up from 5 to 20 days of consumption, or maximum storage capacity. Electricity producers must reach the increased safety levels by November 1.

Electricity suppliers revise tariffs upwards for August

Electricity suppliers have just announced tariff revisions, upwards, for August following the government’s implementation of a five-euro price cap on fixed charges.

These tariffs will apply as of today. Deducting the state’s support, worth 33.7 cents per KWh, the revised tariffs announced by suppliers range between 14.9 and 28 cents per KWh, the majority of suppliers offering tariffs between 23 and 26 cents per KWh.

The government’s decision to impose a price cap on fixed charges – after electricity suppliers opted to increase their fixed charges to keep their tariffs, the competitive aspect of electricity bills, as low as possible – as well as the related legislative revision procedure led to a one-week delay, enabling electricity suppliers who had not made accurate forecasts for August’s international prices to reexamine and reset their levels.

Some suppliers have increased their tariffs for August by 4 to 10 cents, compared to previous levels, set on July 25.

These increases reflect the unrest of suppliers as TTF gas prices continue on an upward trajectory, steadily over 200 euros per MWh. Wholesale electricity prices are now back over 400 euros per MWh, reaching 422.02 euros per MWh today.

Combined-cycle natural gas-fueled power stations will be remunerated at a rate of 422.39 euros per MWh in August, up from 292 euros per MWh in July. Open-cycle natural gas-fueled power stations will be remunerated at a rate of 594.76 euros per MWh in August, up from 408.47 euros per MWh in July. The month-to-month remuneration change for lignite-based production is minimal.

 

 

Taxonomy improvements for gas-fueled power stations

A number of improvements have been made to criteria concerning the entry of natural gas-fueled power stations to the “transitional activities” section of the European Commission’s Taxonomy, intended to serve as a guide for private and public-sector investments required to achieve climate neutrality over the next 30 years.

However, an emissions limit for natural gas-fueled power stations included in the initial plan has been maintained, despite being considered unfeasible by producers.

The elimination of intermediate objectives for green hydrogen incorporation at natural gas-fueled power stations has been embraced as an important improvement by electricity producers.

Initially, authorities had planned intermediate objectives that would have required hydrogen to represent 30 percent of generation at gas-fueled plants by 2026 and 55 percent by 2030. Under the revisions, green hydrogen will need to fully represent generation at these plants as of 2036.

Consultation on the Taxonomy has just been completed, while supplementary terms have been finalized.

Criteria concerning the entry of natural gas-fueled power stations to the EU’s Taxonomy are crucial for Greece, given the country’s number of investment plans for new natural gas-fueled power stations.

These units, according to the National Energy and Climate Plan, will be called on to play an important role in ensuring grid stability and supply sufficiency as the RES sector further penetrates the energy mix.

 

EC Taxonomy prompts gas-fired station sustainability doubts

The European Commission’s just-launched public consultation procedure for new conditions that would recognize certain gas and nuclear activities as green activities, included in a 60-page Taxonomy Complementary Delegated Act distributed to member states at the turn of the year, has prompted uncertainty over the sustainability of new natural gas-fired power stations.

The Taxonomy will determine whether these facilities will be eligible for financial support, and to what extent, through European financing institutions and, possibly, the private sector.

Domestic energy producers are already preparing to forward questions to the energy ministry for clarification on a number of issues.

The Taxonomy stipulates that natural gas-fired generation can be regarded as an energy transition activity as long as new power stations approved before 2030, as replacements for facilities using conventional fossil fuels, emit less than 270 grams of CO2 per KWh.

The European Commission’s plan for completion of the Taxonomy’s public consultation procedure by the end of January, ahead of its implementation by this coming July, is not expected to remain on schedule.

The Taxonomy is intended to serve as a guide for private and public-sector investments required to achieve climate neutrality over the next 30 years.

 

PPC unable to capitalize on lower-cost lignite production

Power utility PPC has found itself unable to take full advantage of current market conditions making lignite-fired power generation lower in cost compared to natural gas-fueled generation as the utility has winded down on maintenance levels at lignite units in anticipation of their expected full withdrawal by the end of 2023 as part of the country’s decarbonization plan.

The utility’s decreased maintenance of its lignite units has led to technical issues not enabling the facilities to operate at full capacity.

The profit margin for lignite-based generation has increased considerably but PPC is not able to significantly boost production for increased sales of lignite-based electricity generation.

Lignite’s share of the country’s energy mix is currently at single-digit levels, registering a 9 percent share in September, according to a recent monthly report released by power grid operator IPTO.

RAE adopts new redispatching system, producers fear cost increases

RAE, the Regulatory Authority for Energy, has decided to move ahead with an energy balancing and redispatching plan in accordance with a formula prepared by power grid operator IPTO following a meeting yesterday between representatives of ESAI, the Hellenic Association of Independent Power Producers, and IPTO.

Public consultation was also staged by RAE on the IPTO formula, prepared by the operator after being commissioned by the authority.

ESAI has expressed concern about the new plan, warning that changes to the current system could increase, rather than contain, balancing costs in the wholesale electricity market, amongst other dangers.

Natural gas-fired electricity producers noted that balancing market revisions decided on ought to have undergone an extensive trial period before being implemented.

 

Second flexibility CATs auction cancelled due to lack of interest

A second and final auction offering flexibility CATs through a transitional mechanism that was endorsed last summer by the European Commission has been cancelled following insufficient interest displayed by gas-fueled producers, who deemed capacity amounts on offer were too small.

Authorities officially attributed the cancellation to a delayed ministerial decision that was needed for the second auction’s staging. But the lack of interest shown by producers with gas-fueled units in their portfolios was at the heart of the matter.

Some sector officials have contended that, given the limited capacities offered, the cost of participating in this second auction may have outweighed any prospective financial benefits.

The transitional mechanism’s second flexibility CATs auction was planned to cover the period running from January 1 to March 31.

According to regulations set for this transitional mechanism, flexibility auctions needed to be staged within the first seven working days in the month following the month of the balancing market’s launch.

Given that the balancing market was launched on November 1, as part of the target model launch, the second auction for flexibility CATs should have been staged by December 7, and, furthermore, a ministerial decision was due by November 7.

Offers submitted by the operators of gas-fueled power stations and hydropower stations fully covered a total capacity of 4,500 MW that was made available at the transitional mechanism’s first flexibility auction, held on October 29. Its flexibility services covered the period running from November 1 to December 31.

Suppliers want lower price limits for producers, retroactive returns

Electricity suppliers are demanding a further reduction to a price ceiling proposed by RAE, the Regulatory Authority for Energy, for balancing market offers by gas-fueled producers, and, in addition, also want an upper limit of 3.5 euros per MWh imposed on compensation for this service.

This 3.5-euro compensation rate per MWh, which reaches approximately 5 euros per MWh when system-loss charges are added, is one of the highest in Europe, suppliers contend.

Suppliers also want electricity and balancing market cost limits to apply retroactively as of November 1, 2020 with returns of resulting amounts owed by the end of this accounting year.

Non-vertically integrated electricity suppliers have reacted strongly against sharply increased balancing market costs and far higher wholesale electricity prices since the launch of the target model’s new markets several weeks ago.

Three of the country’s non-vertically integrated electricity suppliers took part in public consultation staged by RAE, the Regulatory Authority for Energy, to present their objections and proposals, energypress sources informed. The procedure ended yesterday.

 

Balancing market cost hefty for suppliers, €27m in first 2 weeks

Contrary to the satisfaction being expressed by natural gas-fueled electricity producers over the target model’s new markets launched three weeks ago, electricity suppliers, especially those not vertically integrated, find themselves having to pay considerably higher prices for their electricity purchases, which has raised sustainability concerns and could also lead to higher electricity costs for consumers.

Balancing market prices have more than quadrupled, reaching levels of as high as 15 euros per MWh, compared to approximately 3 euros per MWh in the market system used prior to the launch of the target model markets.

This drastic increase has raised concerns among suppliers, who fear the higher cost will eventually need to be rolled out to consumers.

The balancing market’s additional cost for suppliers totaled 27 million euros in the first fortnight of November.

The effort to balance the system is costing consumers millions more, overall, suppliers have warned, noting that, contrary to other European markets, initiatives taken to further liberalize the electricity market are raising rather than lowering price levels for consumers in Greece.

RAE, the Regulatory Authority for Energy, is closely monitoring the situation. The authority believes it is still too early to reach any safe conclusions on the balancing market. If, however, the current situation stabilizes into a permanent condition, RAE will intervene with corrective action, it has informed.

 

Higher gas prices, projected to rise further, not impacting demand

Higher LNG and pipeline gas prices resulting from new market conditions have not impacted gas demand in the Greek market, a key driver being opportunities presented to electricity producers by the target model’s new trading markets.

Latest data has shown a significant price increase in futures contracts at central European hubs, compared to levels recorded just a few weeks ago.

This price rise is seen as somewhat of a paradox given the pandemic’s second wave, now in progress, and its wider impact on demand.

Officials believe the current upward price trajectory heralds an upcoming new round of higher gas prices following extremely low prices in recent times. They sunk to a low in spring.

In Greece, LNG prices are currently rising at a steeper rate compared to those for pipeline gas. Despite this ascent, demand has so far remained strong and no cancellations have been reported for LNG orders to the Revythoussa islet terminal just off Athens.

Pundits have attributed the absence of any LNG order cancellations to the need of electricity producers to be stocked up on gas quantities in readiness for grid entry and utilization of opportunities offered by the target model’s new balancing market.

Local gas-fueled generation up in response to high-cost power imports

Higher electricity prices in neighboring countries, increasing the cost of electricity imports, have prompted power utility PPC to capitalize on the situation and operate its gas-fueled power stations at maximum capacity for satisfactory market prices.

In recent days, PPC’s natural gas-fueled units have covered between 35 and 40 percent of electricity demand.

Yesterday, the power utility’s gas-fueled power stations covered 40 percent of electricity demand at a price of 42.6 euros per MWh for ten hours.

Independent producers covered 19 percent of electricity demand at a price of 64.4 euros per MWh for one hour.

Electricity imports covered 14 percent of electricity demand for a price of 51.7 euros per MWh over 11 hours.

Renewable energy sources covered 24 percent of electricity demand yesterday, while the decreased lignite input continued on its downward trajectory, contributing 3.6 GWh.

In Bulgaria, the wholesale electricity price was 53.14 euros per MWh. In Italy, it was 51.93 euros per MWh. Romania registered a price level of 51.7 euros per MWh. The price in Serbia was 49.91 euros per MWh.

Mid-voltage battle toughens, reflecting lower wholesale cost

Competition between electricity suppliers has intensified in the mid-voltage category, where lower prices currently reflect a sharp drop in the cost of wholesale electricity and, subsequently, wider profit margins available to suppliers.

Competition has yet to intensify in the household and business markets despite discount packages offered by most electricity suppliers, including the power utility PPC, from the beginning of the coronavirus crisis.

This lack of competition has been attributed to a cautious stance adopted by independent suppliers as they wait to see how much profit margin leeway will be shed by a drop in electricity demand and electricity bill payment delays.

It is a different picture in the mid-voltage category, where suppliers are bombarding both existing and prospective customers with price offers.

Suppliers are spreading the risk of wholesale price fluctuations by diversifying their price offers. They are keeping a close watch on the System Marginal Price, determining wholesale prices.

The course of the SMP in coming days remains unclear. Signs of a possible rebound in wholesale electricity prices have emerged as the SMP is now clearly higher than levels registered last week.

Wholesale electricity prices have mainly fallen as a result of increased contributions to the grid by natural gas-fueled power stations, supplied low-cost LNG, as well as RES units.

 

Higher-cost lignite sidelining gas units a Greek market paradox

Greece’s wholesale electricity market is still adjusting as, despite sharp rises in CO2 emission right costs, lignite continues to play a leading market role. Contributions from lower-cost gas-fueled generators remain subdued.

A recent drop in temperatures around the country has led to wholesale electricity market demand peaks of more than 7,500 MW since the beginning of December, up from previous demand peaks ranging from 6,000 to 6,100 MW.

According to the energy exchange’s day-ahead market data, virtually all of the power utility’s coal generators are contributing to distribution without operating at full capacity. Instead, they are running at minimum levels. This is reducing the need for gas-fueled generators.

Yesterday, PPC’s Agios Dimitrios III, IV and V, Kardia III and IV, Amynteo I and Meliti all operated at minimum levels, while the contribution of gas-fueled generators was kept to a minimum. Sidelined units included Heron, ENTHES, Aliveri and Komotini, while Protergia and Korinthos Power units contributed only during peak demand hours.

The picture for today remains unchanged with the System Marginal Price (SMP), representing the wholesale price, at 63 euros per MWh, as was the case yesterday. Before the recent increase in demand, SMP levels ranged between 50 and 55 euros per MWh.

Power grid operator IPTO, offering an explanation for the ongoing dominance of coal over gas, despite the rising demand in the wholesale market, noted that turning off and withdrawing a lignite-fired power station – except for telethermal units – costs more than leaving a gas-fired power station sidelined without distribution input.

For PPC, the objective is to maintain the SMP at low levels as the utility is required to purchase energy from the pool given its big market share in supply and smaller share in production.

CAT flexibility mechanism’s publication to pave way for auctions

Greece’s new CAT mechanism model compensating electricity generation flexibility, a bailout demand taken on by the government during the fourth review, will be uploaded to the EU’s official website either today or tomorrow and is then expected to be officially endorsed soon after.

According to energypress sources, the European Commission gave permission for the Greek plan’s publication a few days ago, once adjustments it had requested were made.

The European Commission is expected to officially approve the new CAT flexibility mechanism soon after it is published, sources informed.

Then, Greek authorities are expected to push ahead with procedures leading to the first auction. Though it is not yet clear how long this could take, environment ministry officials are confident the first CAT flexibility mechanism auction could be staged in July. Preliminary work needed to set up the auctions has already begun ahead of the plan’s anticipated approval in Brussels, the ministry officials noted.

The new CAT flexibility mechanism will operate transitionally until the implementation of the target model, expected towards the end of the first half next year.

Independent electricity producers are keen to see the new CAT flexibility mechanism up and running as its previous version expired in April, 2017. This has prompted financial issues at production units.

Hydropower facilities, natural gas-fueled power stations, as well as RES units will be eligible to take part in these auctions and be compensated for their short-term notice electricity supply to the grid. Compensation for RES units will be limited to output not remunerated through renewable energy support mechanisms.

Assuming no major changes have been made to the plan, the new CAT flexibility mechanism should offer compensation for 4,263 MW of annual output. Hydropower facilities are expected to be entitled to compensation for output totaling 750 MW, up from the previous model’s amount of 582 MW. Starting prices at the CAT flexibility mechanism descending-price auctions are expected to be set at 39,000 euros per MW, higher than 25,000 euros per MW originally planned.

The demand response mechanism (interruptability) – compensating major-scale consumers, such as industrial enterprises, when the TSO (IPTO) asks them to shift their energy usage (lower or stop consumption) during high-demand peak hours, so as to balance the electricity system needs – will not be incorporated into the new CAT flexibility mechanism.

 

Gas-fueled power producers take on LNG tanker security measure costs

Natural-gas fueled electricity producers will assume the cost of a RAE (Regulatory Authority for Energy) decision to hire a tanker for additional storage capacity at the Revythoussa islet LNG terminal, just off Athens, as a precautionary gas supply measure for this winter season.

The details concerning the cost coverage of this measure have been included in an energy ministry amendment of a bill drafted for the establishment of energy communities, promising decentralized, locally generated energy solutions.

According to local regulations, licensed natural-gas fueled electricity producers need to maintain agreements with DESFA, the natural gas grid operator, as well as natural gas reserves.

Costs to be covered by natural-gas fueled electricity producers include the tanker’s hiring and operational costs.

A tanker loaded with 120,000 cubic meters of LNG arrived at Revythoussa at the beginning of this year and will remain docked at the facility until the end of February to offer supply security should high-demand conditions emerge, as was the case last winter, when the system was stretched to its limits.