Recently EEX has launched wind power futures for Germany and Austria to help wind power producers or asset owners manage volume risks and wind induced market price risks. The purpose of this post is to share some thoughts on the applicability of this and similar products for hedging, as well as some issues one might have when calibrating and applying a hedge on own asset(s). The topic will definitely be open to further discussion and exchange of experience, especially when the products actively used for risk management and liquidity start to build up (or not).

With the growing market penetration of renewables across Europe, hedging power from renewables becomes an important issue. Asset owners are understandably looking to reduce the uncertainty of energy output, despite subsidy scheme or wholesale marketing. The number of market participants whose revenues are dependent on the supply of renewable energy is growing as well. To meet these needs, products such as insurances and futures are being developed. However, given the heterogeneity of wind producing sites and the specifics of each asset park or class, a lot of issues arise around the applicability of a single (standard) product as a hedge. Potentially significant basis risk might cause both cashflow implications and inadmissibility of the hedge for accounting treatment purposes.

According to specifications, the underlying is represented by an average wind load factor per period, creating a “baseload” of sorts, based on meteorological data provided by the German Weather Service and turbine database updated on monthly basis. Here is a list of some sources of risk:

• Risk profile and calibration
Difficulties for hedging might arise from wind conditions at a site not matching the wind speeds collected by the meteorological data. Furthermore, the load profile or curve used to transform wind speed data (m/s) into electrical output (MWh) might significantly differ from the turbine type specific curve or the dispatch by the operators. As a result, the hedge instrument might result in a payoff from the buyer (hedger) to the seller (dealer, exchange) not compensated by higher revenues from high wind output. A related issue is how to calibrate onshore met data to offshore wind conditions, as these might differ significantly.

• Availability of assets
Further issue is the technical availability of assets. While turbine manufacturers guarantee a certain technical availability, any unexpected outages not covered by the insurance might trigger payments for the derivative while not generating actual revenues or compensations.

• Price levels
Different subsidy levels and mechanisms are also key in determining how much revenue an asset owner is losing when the asset does not generate. While insurances usually provide individually tailored notional compensations per MWh (based on asset owners’ expected revenues), this is not the case for the broadly defined wind power index. Hedging a renewable asset with a fixed remuneration per MWh based on average load data only (where 1 % equals 1 €/h according to EEX) would hardly compensate for the risk of losing the subsidy, nor the cost to rebalance the portfolio due to over- or under-generation (imbalance cost).

• Intermittency costs
When using an average (baseload) price to mitigate revenues, an issue arises with the so-called profile cost and seasonal uplift of a particular asset or portfolio (majority of renewable production usually during lower priced hours due to the merit order effect). As the load factor is the main determinant of the Wind Power Index, the latter will be unsuitable to mitigate this kind of market price risk. In this case, the best hedge would be to pick a location which best matches the wind output profile on a country level.

Based on the contract details outlined by EEX, wind futures will probably be more suitable for market participants who are not wind asset owners, but are somehow impacted by the wind generation (be it price or volume effects). The latter won’t be confronted with the operational issues described above and the determination of the sensitivity of their portfolios to changes in wind profiles is expected to be more straightforward.

Taking the complexity of calibrating futures to serve hedging purposes into account, a logical question arises whether entering into such contracts constitutes a well-informed bet rather than a hedge for future cash flows? The answer certainly depends on the analytical abilities and specifics of each business. Or maybe sometimes purely on luck?


Written by Konstantin Grigorov

Achieving a Reliable Front Office Reporting in ETRM systems: Typical Pitfalls

Achieving a Reliable Front Office Reporting in ETRM systems: Typical Pitfalls

Achieving a Reliable Front Office Reporting in ETRM systems: Typical Pitfalls

Are you the most trusting person on Earth? If that is the case, you obviously, haven`t dealt with front office reporting solutions, nor have you ever opened a bag of chips.

As the saying goes „Trust is the hardest thing to find and the easiest thing to lose”. When it comes to front office reporting and traders it is even more fragile than a gold fish`s memory. A couple of wrong position results may lead traders to feel like they are using a gambling tool instead of a reporting tool.

A front office reporting project can be complex since it relies heavily on components such as deal modeling, curve/volatility configuration, and simulations results. All of these need to be properly configured in the system in order for front office reports to be correct.

BIG mistake – Reporting is left to the end of the system implementation as it depends on so many system components.Delays however, may result in a rushed reporting roll-out and could lead to issues that subsequently only show up in Production. At this point, since traders rely on front office reporting for position management, this could be easily classified as a showstopper.

By their nature front office reporting projects are rarely straightforward, but typical pitfalls can be avoided if the following points are considered:

  • Front office reporting is a team effort. It requires collaboration between:
    • End-users – need to define requirements in terms of the type of data they want to see, details of how the data should be organized, and performance expectations;
    • Business consultants – need to map end-user requirements to the system`s features and identify any gaps between requirements and system capabilities;
    • Technical consultants – need to take the performance expectations from the end-users and the front office configuration elements from the business consultant and map this to the system configuration.
  • Front office reporting is often underestimated by thinking it is just as a simple matter of putting the appropriate columns and filters on a page. Instead, it is important to understand the actual data to be produced, and what it will be for each deal type in scope.
  • The process of analyzing the data given by the reports and comparing against client needs is not started early enough in the project timeline. It is favorable if a design document for the reports is to be created early in the project, even if the pages themselves cannot be built yet.
  • Estimation of how difficult something is to be completed during implementation is often done by analogy. This however sometime fails to appreciate the differences between underlying data, especially in regards to granularity.
  • Overseeing a needed customization is costly in terms of additional time and effort necessary. Furthermore, due to the sequential work among multiple teams, it can often lead to project delivery delays.
  • Focus on the server side first. Take into account reports` sizing and performance early in the project. Inappropriate technical sizing may lead to production issues. Front office reports may deliver correct numbers when a deal is booked in isolation but that doesn`t necessarily mean that they will work optimally when under peak load, if the hardware is inadequate. This sizing adequacy is driven by business requirements which often change over time.

Taking note of the above pitfalls could save you and your clients a lot of frustration. Failing to acknowledge them will lead to a reporting that users are reluctant to use as they do not trust the results.

Written by Maksim Yachev

RES support tenders – increasing competition or emergency brake?

RES support tenders – increasing competition or emergency brake?

RES support tenders – increasing competition or emergency brake?

Renewable energy sources (RES) have played a key role in European policies over the latest decades and will most probably continue to do so in future. To reach their targets for electricity consumed from RES, EU countries have applied a number of support schemes, which often have been revised (in many cases more than once) for one or another reason. As a professional, who has experienced the renewables tariff roller coaster in first person, any announcement of changes is already bad news. Auctions and/or tenders, increasingly gaining popularity within the EU as instruments to increase competition among different renewable technologies, are no exception. A person like me, who has developed a healthy pessimism against frequent subsidy changes caused by the evolution of the support schemes, may ask the following question: Is the urgency to curb the rapid RES development and the associated budget deficits the primary motivation behind the reforms or could it be the next logical step in the evolution of renewable energy support?

According to a recent document published for EU-28, the development of the RES shares constantly exceeded the expected trajectory in the period 2010-2014. This has determined Europe’s leading position in terms of energy investments, which was only recently overtaken by China. Advantageous feed-in tariff levels in Germany, for example, have obviously attracted economic interest for much more installations than originally anticipated, raising the renewable energy levy (EEG-Umlage) in energy consumers’ bills from 0.20 ct/kWh in 2000 to 6.24 ct/kWh in 2014. The rapid growth of RES has caused tariff deficits i.e. a gap between the cost of electricity generation and what consumers pay, in a magnitude of billions in Spain in 2013, leading to significant support reductions, some of which were even applied retroactively. The latter triggered a chain of lawsuits from the business against the state. The value of green certificates (GCs, type of market-based RES support with quota obligations set administratively) in Poland has declined dramatically due to the oversupply of the GCs market. Frequent revisions of subsidies also took place in Italy, Portugal and other countries. Many of these developments I have experienced live by taking part of the risk management and valuation of the assets directly impacted. Besides the loss of value, the loss of trust is a negative consequence of the frequent changes in governing legislation. It discourages the business from further investments. This is, as far as I can tell, a rather harsh reality than a textbook argument. In the context of growing caution by investors, tenders with fixed levels (caps) of support per technology might act as an emergency brake to prevent any potential negative trends before it’s too late.

Typical competitive allocation mechanisms like auctions or tenders are designed to distribute financial support cost effectively by letting the business decides which bid for a particular energy source will be deemed acceptable. Whether the direct consequence of their implementation will be an increase in competition or a decline in renewables growth (both already witnessed in practice), is up to the government tailoring the rules. Too high received bids (e.g. based on perceived as fair feed-in tariffs plus a premium) or too low maximum prices could undermine competition or even lead to non-feasible projects winning the tenders. Such scenario will definitely slow down the current rapid development of RES projects. Certain pre-qualification criteria might prevent cost-effective technologies from bidding. Auctions performed infrequently, irregularly and in an unreliable way might well act as weapons in the hands of regulators, who are looking for quick wins in budget savings. For many RES, subsidy reforms may prove to be a road to Hell paved by good intentions, and for individuals mostly pessimistic about changes in rules – a prove of their attitude. The final verdict will definitely depend on the country specific design of the auctions. So far, Germany seems to be paving the way towards introducing competition by-the-book and reaching the intended results by the EU. Let’s see what the future holds for the others.


Written by Konstantin Grigorov

Navigating the EU State Aid rules, when implementing a capacity mechanism

Navigating the EU State Aid rules, when implementing a capacity mechanism

Navigating the EU State Aid rules, when implementing a capacity mechanism

More often than not understanding what to expect from an upcoming EU regulation can be a challenge. I have been through a good number of its energy trading regulations and still at times, I am left wondering, how implementing the next one will unfold. And yes, my expectations often prove wrong. Yet, I keep trying to understand and see the logic of it all. So, when I’ve read that the EU finally approved France’s new capacity support scheme after few changes ensuring its compliance with the EU State Aid regulation, I’ve decided that a quick overview may help us all understand, what are the key rules to be upheld.

A number of generation capacity support measures are expected to appear across the continent, all with the purpose of ensuring energy security. However, all such measures need to be in line with the EU Guidelines on State aid for environmental protection and energy, issued in 2014 in an attempt to ensure that the key principle of free competition across the Union is preserved. This regulation defines the conditions under which state aid for supporting additional capacity is permissible. Its objective is to correct for the inability of the energy market at its current state of liberalization to adequately compensate investors for bringing additional capacity on the market. One of the EU MS, which attempted this State Aid puzzle is France. It introduced a Capacity market obligation mechanism to ensure there is enough of it to satisfy its peak load. The measure introduced was supposed to steer clear from all EU state aid requirements by being structured as public service obligation. However, the latter did not stop the EU Commission to put France’s first capacity guarantee auction on hold until it reviews the entire mechanism for compliance with the State Aid regulation. Why and what a country considering any capacity support mechanism may expect in the light of the above?

So, in a nutshell, the State aid regulation requires:

  • The measure to be open to all technologies possible including demand response, energy storage and additional interconnection;
  • The support amount to be as little as economically possible;
  • The mechanism to be open to participation from operators across the Union, if this is physically feasible;
  • The country introducing the mechanism to do a thorough analysis beforehand on any currently existing market distortions, which may have caused the capacity shortage and address these upfront;
  • The aid not to have a negative effect on the competition in the EU energy market;
  • The measures to be effective in attracting new capacity;
  • The measures to reward only capacity and not generation of electricity;
  • The measures to give preference to renewable capacity, when everything else is being equal.

The requirements are clearly in line with the overall energy policy of the EU for free market competition, with the goal for creating a joint EU energy market and encouraging environmentally friendly ways of meeting the EU energy demand. The goals are clear, the way to achieve them not so much. There is a lot of ambiguity about how to reliably evaluate the impact of the existing market distortions or intended measures, provided the complexity of the system. This is exactly the point, which attracted the scrutiny of the European Commission in the case of France.

In its press publication from 13th of November 2015 the EU Commission has expressed its concern that the capacity mechanism may distort competition and prevent certain market players from entering the energy market. It is the commission’s concern, that French capacity mechanism may not be done in the most cost-effective and competitive way. Furthermore, the Commission suspects that the mechanism may not result in additional capacity entering the grid. On the 8th of November 2016, the Commission finally announced its approval for the French capacity mechanism. The changes, which secured this approval, are allowing for new market players and foreign capacities to enter the scheme and introducing a series of measures to prevent possible market manipulation.

This investigation and the following approval mean that the French mechanism is indeed considered a state aid (1) and its necessity (2) appears to be justified in the Commission’s view, while corrections needed to be introduced to address its efficiency (3) and effectiveness (4). The conclusion is that the Commission will uphold its requirements, even when considered contradictory by some. Not doing so will directly undermine its goal of creating a single European energy market. Additionally, capacity support mechanisms being a novelty in Europe will have to go through several iterations before settling upon a mechanism, which will meet the requirements of all stakeholders.


Written by Snezhina Mileva

Will UK power capacity market face shortage?

Will UK power capacity market face shortage?

Will UK power capacity market face shortage?

Can you imagine waking up in the morning and skipping the hot cup of coffee due to power shortage? Can you imagine skipping the hot shower due to power shortage? I can’t. But it could happen.

If you want to know what measures the British institutions have put in place to improve the current situation in the power sector, you should definitely read below.

The plant margins in Great Britain have declined in the recent years and this trend is expected to continue also in the future. This is based on the plant decommissioning and the low levels of investments in new capacity.

Great Britain’s electricity market has no explicit reward for conventional generation capacity other than some ancillary and balancing service payments. Some support is available for the renewable generation but this is a different story…

European Commission approved the new state aid guidelines in the middle of 2014. The Capacity Remuneration Mechanism (CRM) adopted by Great Britain became the first case notified by the Commission according these rules. Since this Mechanism gives an economic advantage to the certain participant, it is classified as “state aid” and therefore requires approval by the European Commission.

The Commission’s decision not to object to the CRM being implemented by Great Britain is now the subject of a legal challenge by Tempus Energy in the European General Court. Meanwhile, CRM has been implemented in the country.
The mechanism itself consists of a number of stages among which are the establishment of a reliability standard, assessment of the capacity necessary to meet that standard, pre-qualification, the capacity auctions, secondary trading, delivery and obligations.

As already mentioned, the forthcoming plant decommissioning together with a lack of new investment has raised concerns about future capacity margins. This has led to the introduction of a reliability standard. In order to be within the required standard the annual loss of energy expectation should not exceed 3 hours/year.

The System Operator is the one assessing the capacity required to satisfy the reliability standard. This assessment is the base for the amount of the capacity to be procured via the capacity auction. The first auction took place on December 2014, considering 2018/2019 period and 48,6 GW of required capacity.

The next step after the assessment is called pre-qualification process. The pre-qualification is necessary to establish the total capacity of potential providers.

The auction itself is a two-stage process. The first stage is held four years before the delivery year (the T-4 auction) for each delivery year. This step is followed by a second auction in the year prior to delivery (the T-1 auction).

There are short and long term contracts. All Price takers that bid below the market clearing price will be awarded contracts of one year duration. The projects for newly built plants should be awarded with 15-year contracts and last but not least all projects for refurbishment should be granted with 3-year contracts.

The System Operator invented the so called stress events for which the participants get annual payments for being available to deliver. Every time the participant fails to deliver contracted capacity during a declared stress event penalty will be imposed.

The System Operator have tendered for two new balancing services which should serve as means of transitional arrangements for the interim period before delivery in 2018. These two balancing services will be utilised as a last resort in order to prevent demand reduction. According to this mechanism, all large consumers who have flexible demand and generation could participate in meeting peak demand when capacity is scarce.

Summarizing at the end, as already mentioned, Great Britain capacity market was implemented to reform the power market and to solve the problem of falling capacity margins and the lack of investments which would lead to capacity shortage after 2018. Since similar concerns arose in a number of Member States, Great Britain’s response in terms of power market reform and introduction of this Capacity Remuneration Mechanism to support investment in new capacity may be of some interest to other EU countries.


Written by Valentin Pavlov

End-Of-Day made simple: Mission impossible?

End-Of-Day made simple: Mission impossible?

End-Of-Day made simple: Mission impossible?

Imagine you come to work around 7 am to prepare for the trading day. You expect a set of reports around exposures, PNL, MTM, etc to give you your starting positions and to help you make decisions what to trade today. They are missing. Someone in IT explains the End-of-Day has failed and it is re-run as we speak.

You take a sip of coffee and wonder whether to shout to someone. Then you go back to Excel and start to recover what happened yesterday to make sure you don’t trade based on wrong positions.

Sounds familiar?
Well, End-of-Day, after all is a mythical monster, working and failing in mysterious ways. A lot of trading companies have fought to provide a stable, predictable, and performant EOD process for a while. Below are some thoughts on how to achieve it and what to look after.

EOD (End-of-Day) is a daily process. ETRM systems need certain processing to occur each day in order to correctly handle the captured trades. The EOD process consists of a series of operational functions that process the trades.
Normally, one would want as lean EOD process as possible or in the words of Antoine de Saint-Exupery: “Perfection is Achieved Not When There Is Nothing More to Add, But When There Is Nothing Left to Take Away”

The EOD process may be either fully automated or semi-automated with some jobs from the workflow requiring manual work. Full automation typically calls for custom solutions. Depending on whether the process is fully automated or not, the EOD workflow may be done entirely during the night or partly during the night and during the day (when manual work is required). A typical example of manual work that could be required is the “price upload” job. In cases of required manual work, usually a messaging task is created that sends a message to the responsible person to do the job. He then sends a message back if the task is done which triggers the next one in line.

In the best case scenario there would be a separate server for the EOD process. As it requires date rolling, this could be disruptive for business-as-usual processes during the day. Therefore, EOD timing should be taken into account in order not to hinder other processes in the system. The amount of time it takes for EOD to complete depends on the computing power, the complexity of the workflow (+amount of data calculated). Possible disruptions of the process should also be taken into account (failed jobs) and predefined if certain failures stop the whole EOD process.

The jobs comprising the EOD workflow could basically be started on two principles: time and event triggered. Normally, there is a chronological hierarchy of the tasks that need to be performed for EOD. The problem with scheduling tasks on a time principle is that they may not always finish on time due to various reasons. (If there is some manual work to be done for a task to be completed, users may not be able to perform it on time; price assessment agencies could fail to deliver prices on time, etc.) Normally time scheduled tasks in EOD will be only used when event triggered ones cannot be used or require too complex setup.

It is important to remember that the End-of-Day process is set to achieve the following basics:

  • Prevent users from forgetting to perform their daily tasks by means of automation.
  • Achieve automation by scheduling of tasks using a time or event trigger.
  • Provide information that is requested by management on a daily basis (Position Reports and trade listings)
  • Perform all tasks that are a prerequisite for successful use of Endur. (Data Maintenance, Price Fixing, Roll System Date, Data Upload)

Having this in mind, one should try to set up an EOD process as lean as possible that manages addressing all of the above in accordance to the specific organization`s needs.

Written by Maxim Yachev