In February, the Energy Networks Strategy Group published a paper called ‘Our Electricity Transmission Network: A Vision for 2020’. At 148 pages it sets out in detail the potential generation and demand background which meets the UK targets of 15% of energy demand being provided by renewable sources and a 34% reduction in Green House Gas emissions by 2020. It also takes into consideration what would be required to meet the Scottish and Welsh Governments’ 2020 renewable energy targets i.e. the equivalent of 100% of Scotland's electricity demand should be met from renewables and 7TWh pa of Welsh electricity production by 2020.   With customer demand assumed to be static (at ~ 60GW), Global Energy Advisory has long made the point that it is policy which is driving investment, not demand, with end customers picking up the costs.

The purpose of the report was to determine what was required to accommodate (that is connect and transmit) a further 38.5GW of new generation (a little under half of current generation), of which 23GW could be a combination of onshore and offshore wind generation on to the system. The investment is £8.8bn, which is an increase of previous estimates by £4.1bn which is largely due to including the costs of possible provision of new subsea links from Scottish Islands (Western Isles, Orkney Islands and Shetland Islands) to the mainland.

The power market in the UK is currently under reform with the introduction of a new capacity market planned. So if existing and new plant both receive capacity payments (there are none now); and with an additional 38GW of new plant and ~100GW on the system, then, even paying for capacity could be very expensive or literally un-affordable for customers.

Part of the reason there could be so much plant on the system is that the nuclear fleet in the UK has received between 5-7yr life extensions. There is also the assumption that the first new nuclear plant connects to the grid in 2019/20. Coal plant closes due to environmental directives, but 12GW of new conventional CCGT capacity could be built. However, there could be a staggering 26GW of wind capacity in 2020 with 17GW being offshore. It is also possible that interconnections could be supplying the UK at some point; these could amount to another 6.7GW of capacity[1].

 The report notes.

 “The predominant power flow on the GB transmission system is from North towards the South. In the North of Scotland, generation is assumed to significantly increase with onshore, offshore wind and marine renewables. The level of demand is not anticipated to increase… Accordingly, there is a predominant net export of energy from the region to the Central Belt of Scotland. Additional power flows in the Central Belt of Scotland, within the Scottish Power Transmission network, would place a severe strain on the 275 kV elements of the network and, in particular, the north to south and east to west power corridors. The Upper North network of the England and Wales transmission system also experiences increased power flows which require reinforcements on the system. The increased power transfers across the North to Midlands boundary and/or the increased generation off the East Coast and/or Thames Estuary could result in severe overloading of the northern transmission circuits securing London especially when interconnectors around the South East area are assumed exporting to mainland Europe, hence the need for reinforcing London networks”.

Capacity is about potential to generate which is different from ‘energy generation’ because power-stations do not produce at their name-plate capacity (MW) all of the time. However, having so much generation potential/capacity on the system will mean there will be times when there is not the space to allow all of the power plants to generate at the same time. When this happens they get paid for what is called “being constrained off”. It would be an inefficient power grid that has too much power generation and in the wrong place.   So without the £8.8bn of investment then there could be strain on the grid and maybe not all the power will be able to flow all of the time. The problem is that constrained off payments can be very high, which is not in the interests of the end customers who ultimately pick up the costs.

Constrained Off Payments

National Grid, who operates the UK high voltage power transmission system has to abide by rules and regulations. When the power grid is constrained, National Grid has to compensate the stations that would have been generating for the lost sales as if the power plant had been operating. For example when say a coal power station is constrained off the power grid, the National Grid actually pays the system operator a sum less the fuel saved by that generator. The average price per MWh constrained amounted to £215 MWh, with the range being £150MWh to £800MWh. The problem is, that when some renewable generators are constrained off then they are not just paid for the energy profit but also Renewables Obligation Certificate (ROC) foregone, worth approximately £50 per MWh, plus the Climate Change Levy Exemption Certificate (LEC), which is worth approximately £4.85MWh. Therefore constraining off renewable generators can be costly.

Importantly, on the 23rd of May 2011 between 14:40 and 17:10 National Grid was simultaneously transferring English electricity to Scotland and also paying two Scottish wind farms to reduce generation. It was thought because the wind was unpredictable that day that either the generators could not forecast their production for the system properly, at a time when National Grid obviously had difficulty balancing the system. An investigation was made, but the payments were considered not ‘unusual’ but as an indication of an ongoing structural problem in the network. Can we therefore deduce that with so much plant on the system, in places where it’s hard to transmit the power from; that the number and amount of constraint generation will increase? There must be a better way.

Power Source

If there is too much generation available on the grid, then customers with flexible energy use could consume more. Similarly, if the grid is under stress when there is potentially little wind out-put or a problem on the system then customers with flexible energy use could consume less. It will not just be the National Grid who will be looking for consumption flexibility but the energy traders and even the companies that operate the lower voltage networks as they too need to push demand around their systems to keep the local power gird safe. Also it has to be the smaller customers in the local area, at what we call the embedded level, to respond. Therefore if you are a customer who can be flexible in how and when you consume, we thought it fair that you should be compensated for helping to keep the lights on.

Currently National Grid uses STOR[3] to keep the system stable, but this is mainly in the form of back up generation, rather than flexible consumption. However, Mr Ed Davey, the Energy Minister, told the Scottish Lib Dem conference in Inverness on the 3^rd of March: “(This is) the first government to seek to make reducing energy demand at least as important as how we increase supply”. Energy efficiency and the demand side response as it is known has been a elusive objective in past decades, but now it will be in timely demand. The problem is that National Grid has never needed such a wide-scale response as they will need in the future and customers don’t know how to go about making them-selves known for balancing services.

Prisim[4] is a commercial framework, structured by Global Energy Advisory, which unlocks the flexible load response at scale. To us it seemed fairer for customers, who ultimately pick up the costs of future network connection and investment, get a chance to earn a market return for helping the grid to keep in balance. Prisim customers also provide balancing services at competitive cost compared to generating units whose prices we have seen vary from £150MWh to £800MWh.  National Grid is a company of engineering excellence, but in the future, as the constrained payments are showing, he will need more flexibility from all customers to keep the power system in balance and asking customers to take a bit more power could be very helpful indeed.

If you would like to earn revenue for being flexible with your energy use then for more information contact:

Dodd Frank and European Financial Markets Regulation, The Ability to See Potential, Where Others Only See Problems

On 15 February, Moody’s Investment Services announced rating actions affecting 114 financial institutions in 16 European countries.  Moody’s also said ‘the highly interconnected financial markets and economies imply elevated uncertainty for all banks, even those banks that have shown resilience thus far’.   That does not sound good.  Possible wide-spread credit down grades for such a large and important sector could have consequences for the other industries, including commodities. 

It’s not just the banks that are undergoing review but their long-term debt, deposits and in some cases their short-term and subordinated ratings too.   Moody’s also note that bank’s have disrupted markets, weakening sovereign credit worthiness and a deteriorating, uncertain economic outlook to contend with.  So the European financial markets have their own challenges at this time.

One example of deleveraging was on 22nd February, Wells Fargo announced and agreement to buy an energy loan portfolio from BNP Paribas with a historical value of $11bn.  If European banks are selling energy loans then it doesn’t demonstrate an appetite to lend more.     However, this is precisely what we need them to do, as it’s very possible that the European energy sector will be caught by the same financial markets regulations that banks are exposed to themselves. These new legislations (Directives and Regulations) call for increased clearing, reporting and margining against positions.  

In the USA, on the 23rd of February, the Commodity Futures Trading Commission (CFTC) was expected to declare 40 non bank firms to be registered as dealers who would then have been caught by the Dodd Frank regulation.   But a few days before the CFTC postponed the vote placing the blame on the Securities and Exchange Commission (SEC).   If a firm is characterized as a swap dealer then they are caught under the new trading regulations, and currently if you trade more than $2 billion of the risk-management tools (swaps) then you are caught.   

Credit Climate Some large trading firms have said they require margin capital of $1bn to comply with the new regulations, others say ~$2bn. What then should we consider the amount the commodity industry may require globally?  Is the number $100bn or more? Bloomberg reported on the 18th November, 2011 that ‘companies from RWE AG (RWE) to Vattenfall AB may have to find an extra $69 billion Euros ($93 billion)’. Margin requirements will also increase as commodity prices rise.   So what is the number and can we find a solution to this?  

The Ability to See Potential, Where Others Only See Problems

There is an alternative to traditional margining: Credit ENhancement of Traded EneRgy (Center).  Center is an established, proven settlement platform currently used in non-energy industries. To date over $54 billion has been processed through the platform, 100% error free.

Center is a collaborative mechanism whereby two counterparties agree to use the Center settlement platform to generate margin capital. This capital is supplied by approved third-party investors who have appetite for the risk profile. The structure is used to dissipate the commodity credit risk into the wider financial markets.

Example: If two counterparts are trading together where the position is subject to a MTM calculation, one party will be in-the-money (ITM)/profit, and the other out-of-the-money (OTM). The counterparty with the OTM position could pose a credit risk to the other trading party, and be asked to post collateral.  Traditionally, this has been in the form of posting cash or a letter of credit, depending upon the size of the risk.  However, letters of credit and cash are expensive and use up vital bank lines.

By using the Center product, the ITM trader would calculate the amount of collateral required from the OTM trader to restore credit risk to acceptable levels. They would then ask (through back office processes) for the OTM trader to issue a Center “Payment Instruction” through the Center solution in favour of the ITM trader. Once this Payment Instruction request is issued and approved by the Center settlement platform, it becomes available for third-party investors to fund and the discounted cash is passed to the ITM counterparty within two business days.

Turning Risk into Return

Even if a firm is cash rich and happy to post cash against their trading positions, they could use the Center product to earn a superior return by using it to invest in the marketable securities issued by the platform. What could be a safer investment for the Treasury team than a firms own credit risk?  So by using Center you can mitigate credit risk, be a responsible counterparty, save on financing costs and earn a relatively secure commercial return. And there are no legal costs or arrangement fees for using the Center platform, the cost is the carry, with added margins for the credit risk of the OTM trader and maintaining the system.

For more information contact or visit our CENTER page

Companies from RWE AG (RWE) to Vattenfall AB may have to find an extra 69 billion Euros ($93 billion) to meet unprecedented European Union regulations designed to crack down on speculation in the region's energy markets. A proposal made last month by the EU may for the first time require utilities and other firms with commodity assets to set aside funds to clear, or safeguard, their power, fuel and carbon permit trades against default. Those companies don't currently need to clear so-called over-the-counter, or OTC, trades, which, in power, account for 73 percent of Europe's electricity market.
Bloomberg: 18 November 2011

Global Energy Advisory Comment: This is a massive issue for the energy industry and will have a direct impact on customers' bills. The large European utilities may appear to be too big to fail, but given the price risk in trading energy, big energy firms do fail as did TXU Europe a few years ago. In energy we have a concentration risk, so if one firm fails they can cause a daisy chain of other failures. Credit risk is increasing as commodity prices become even more volatile so credit risk management is not a luxury; it's a basic requirement of trading responsibly. With the European banking market distracted bank lending to support this cash need is likely to be difficult. We anticipated this and structured the Center product a number of years ago. Center dissipates the energy trading credit risk into the wider financial markets. The specialist credit committee of EFET (European Federation of Energy Traders) reviewed the product and saw its merits especially in the context of managing settlement credit risk.