We believe this should matter to any company developing low carbon buildings, and we explain why.

With tightening carbon targets for new houses, housing developers, social housing providers and councils are all focusing on installing low carbon energy for new buildings. Many of these schemes involve district heating networks, combined heat and power (CHP) plants as well as a mixture of renewables. Rather than a world where the developer installs individual gas boilers and then has no ongoing energy involvement once the development is completed, housing developers are forced to provide energy services on an ongoing basis, either by themselves or through the procurement of an energy services company (ESCO). Part of the process of procuring an ESCO is to understand the commercial viability of the energy sales and forecasting future electricity prices. This includes understanding the sites’ generation costs, likely customer tariffs, distribution costs, cost of additional electricity purchases and supply costs (e.g. cost of billing, meter reading etc). In this context, the cost of electricity in the wider market has a profound impact – not just in the feed through into competitor’s customer tariffs, but also into the cost of procuring additional energy on site. Poor understanding of electricity pricing can have a profound future impact on the viability of the energy side of a development. There are four key things you should know:

1. The difference between retail prices and profit

One common misconception we see in business plans for new developments, is that the retail price of electricity less the cost of generation equals profit. This is not true – supply margins are very small and generally the difference between the wholesale cost of electricity (the time average cost of generation on the system) and the retail tariff is the various costs of supplying electricity such as the fees for using the distribution network. Profit lines in business plans should be based on wholesale electricity prices not retail prices – wholesale prices may be (say) 4p/kWh versus 10p/kWh of retail price to the consumer. In this example, overall profit is more like 1.5p/kWh not 6.5p/kWh.

1. Not all electricity has the same value

Electricity value varies widely between day and night as well as between summer and winter. In winter, overnight electricity can be worth one third of electricity at the peak half hour. In fact, the Pöyry intermittency study suggests that the difference between night time electricity prices and day time prices could widen significantly with excess wind generation causing negative prices over night (i.e. generators will not get paid for their spill generation but will have to pay to generate overnight).

This matters for new housing developments because the general profile of these developments is a combination of continuous electricity output from a CHP and some intermittent output from renewables. The profile of the users on the site will follow the general consumption patterns for the electricity grid as a whole, with significant variations in demand over the day and during the year. To meet the carbon targets, on site energy assets do not have to match electricity demand on an instantaneous basis – but the electricity market matches on a half-hour settlement system. As a result, most developments will have excess generation at night and insufficient generation during the day time leaving them vulnerable to poor value from overnight electricity sales and exposure to high day time prices.

1. Getting the renewable energy value right

Renewable energy has value through the issuance of renewable obligation certificates (ROCs). These certificates are sold in the open market and potentially give significant additional value over and above the value of the energy generated. In addition, government is introducing a fixed payment called a feed-in tariff for small generation, which will be instead of the ROCs, and a renewable heat incentive for heat generated from renewable sources such as biomass. There is potentially a lot of additional value here for renewable assets installed in housing developments, but it should not be overvalued. For example, ROCs are likely to be limited to 20 years for any generation asset, so don’t extend the ROC payments to match the life of the asset. Some technologies like solar photovoltaics (PV) generate 2 ROCs per MWh of generation (instead of the standard 1 ROC per MWh), but government is likely to down grade the ROC allocation as PV generation becomes more prevalent – although government has traditionally allowed existing assets to continue to receive the higher ROC allocation when it has downgraded the ratings, there is no guarantee that they will do that in the future. Finally, feed in tariffs and renewable heat incentives also face similar regulatory risk and revenues should be forecast carefully.

1. How to supply customers on licensed distribution networks

One final issue to bear in mind is projects that plan to use an unlicensed electricity supplier over a licensed distribution network. Typically we see those for projects where there are more than 1,000 homes but less than 2,500 homes (where you can make use of the 2.5MW exemption for supply on licensed distribution networks) or for retrofit schemes where houses are already supplied on a licensed distribution network.

For retrofit schemes, you cannot force a customer to be supplied by the onsite energy (unlicensed) supplier – you will have to market to them and encourage them to switch over. Assuming 100% transfer over of properties within the scheme area is extremely unlikely, even if prices are heavily discounted. Around 40% of electricity customers switch supplier each year – so a 100% switch rate would be extraordinary – and retaining 100% of the customers to switch to you would also be unexpected.

Supplying customers over a licensed distribution network means that you will pay the full distribution charges to use the network including generation connection and use of system charges and full distribution customer charges. These costs must be explicitly included for business forecasting.

More than that, we are not aware of a single project that makes use of the right to be an unlicensed supplier on a licensed network. In fact, after speaking at length with Elexon, who operates the market rules, we have not yet found a way to comply with market rules and be unlicensed within the licensed network. Bear this in mind when reading rosy projections of revenue streams for projects.

In practice, until the Department for Energy & Climate Change (DECC) decides whether to change the regulations and a revised exemption order, possibly not until 2010 or beyond, what can developments do to ensure that they are able to offer third party access if required?  What is necessary?  Does it just mean ensuring that electricity meters that are installed within the private wires meet the technical standards of the licensed distribution networks and the electricity market?

A bit about the electricity settlement system

Unfortunately, the answer is not that simple and it comes back to the structure of the trading arrangements for electricity.  Electricity trading arrangements are governed by the Balancing and Settlement Code (BSC).  Under the BSC all meters, which are connected to the licensed distribution networks (including the boundary meter for private wires but not the meters within the private wire network) are registered in the industry wide settlement systems.  The supplier submits meter readings to the settlement systems and each are allocated a unique meter number known as an MPAN (meter point administration number).  For half hourly metered customers, consumption data is submitted to the settlement systems daily for each half hour.  Non-half hourly customers have a meter which is an advance meter i.e. it records total consumption, but not the time at which it is consumed.  Suppliers must submit information at least once a year for these non-half hour meters.  As a result, the deemed consumption for each customer is determined according to a “profile” and there are 8 different profile classes for non-half hour customers.  Aggregated over large portfolios, the inaccuracy in the allocation of electricity volumes evens out, but is more significant with a small number of customers.  Settlement takes 18 months to complete with a number of settlement runs of increasing accuracy.

The reason that a customer cannot change supplier is not because it is blocked by the private wires operator, but because the meter is not recognised by settlement and so there is no forum for settlement to occur and therefore to supply that customer.

To provide third party access on a private network, the private wire operator must put in place arrangements which allow suppliers settle the electricity volumes and to distribute electricity across the private wire network.  We have identified two possible options, both of these options give residual risk to the private wire operator.

Physical settlement on a private wire network

It is possible to implement a “meter volume reallocation” at the boundary meter. This allows some of the volume registered by the boundary meter to be allocated to a different supplier and transferred away.  In this case, you would register the customer who has changed supplier’s meter into settlement with an MPAN and you take their metered energy volume off the boundary meter total through a “meter reallocation”  The customer then is “supplied” by the third party and the private wire party has a reduced volume at the boundary meter for which it contracts with its top-up supplier (this may nominally increase recorded outflows even though physical network flows have not changed).

In addition, the private wire operator must develop a “network code” (rules for using the network) and price tariffs for using their network as they are allowing a third party to supply.  The private wire operator will charge the third party supplier for using the distribution network in accordance with the price tariff it sets.

The physical settlement method outlined works reasonably well for a half-hourly customer who changes supplier.  In this case, there is no volume risk as the customer’s actual consumption is transferred to the new supplier.  For a non-half hourly customer who changes supplier there is a residual volume risk.  This arises because the boundary meter is settled half hourly on actual metered data whilst the non-half hourly customer is settled based on a profile of consumption.  In practice, there will be differences between actual consumption and the profile giving a mismatch on a half hourly basis between actual energy consumed and the boundary meter reading less the profile consumption of the non-half hourly customer.

Financial settlement on a private wire network

With the difficulties for non-half hourly customers with a physical meter reallocation, it is possible to offer financial settlement instead.  In this case the private wire operator will continue to physically supply the customer with power and there is no change in metering or the boundary meter.  However, the private wire operator charges the third party supplier for the energy consumed and also for use of its distribution network.

The price at which the energy is charged could be set against a wholesale market index, of which there are a number to choose from.  In addition, the private wire operator will charge for the use of its network.  The third party supplier will remain liable for other supply costs such as transmission and the renewable obligation etc.  The private wire operator will have to provide a “network code” and distribution price tariffs.

Unlike the meter reallocation option, this requires a direct relationship with the supplier and also gives some residual price risk of the difference between own generation costs and the wholesale market rate.  But there is no volume risk and this is advantageous with non-half hour customers and also where there is substantial onsite generation (to avoid settlement values of export from the site when in fact all the energy is actually consumed on site).

So where next?

Unfortunately, offering third party access is not just a register a meter or pay-a-fee solution, nor is there total certainty on what DECC will allow in the proposed changes to the regulations.  Clarity is unlikely before 2010, but so far DECC have indicated that they are minded to have a “light touch” approach to third party access.

Both options described above are technically possible: one with residual volume risk and one with residual price risk.  It is important to understand these risks in view of the customer types connected to the network.  Regardless, both options require a transparent tariff structure for any third party to use the network and standard terms for usage so that third party access is applied consistently to all suppliers who wish to supply customers on the private network.

Subject:  Definition of zero carbon homes and buildings

Opening date:   17/12/2008

Closing date:   18/03/2009

Subject:  Carbon Emission Reduction Target

Opening date:   12/02/2009

Closing date:   14/04/2009

Subject:  Financial viability of the eco-towns programme

Opening date:  05/03/2009

Closing date:     30/04/2009

Subject:  Heat and energy savings strategy

Opening date:   12/02/2009

Closing date:   08/05/2009

Subject: Community Energy Savings Strategy

Opening date:   12/02/2009

Closing date:   08/05/2009

Although the process for obtaining a license is straightforward, it sets a series of requirements on licensees, including signing and complying with a long series of industry codes.  These codes require specialist energy staff to comply with and also require extensive IT systems.  This results in potentially millions of pounds of start up costs as well as high levels of ongoing costs.

Ofgem plan to make this easier by allowing a revised form of electricity supply license (license light), where a licensee does not need to comply with the codes, provided that it puts in place alternative arrangements with a fully license supplier who is a signatory of all these codes.  Effectively, provided the energy services company can sign a suitable agreement at reasonable cost, it can avoid millions of pounds of costs over the life of the energy services agreement.

This raises a number of questions for developers with sites over 1000 homes:

1. With license light, can I operate as if I was an exempt supplier?
2. Will any fully licensed electricity suppliers wish to enter into such an agreement to supply a contract to a license light party?
3. Given the complexity of the likely agreement, how would you set about putting one in place and then administering it?
4. What will it cost?

Does license light allow me to operate as if I was an exempt supplier?

License light will not resemble exempt operations with a service agreement.  Although the proposals will turn off several license conditions, many remain in force.  There are two key points:

1. Energy flows will not be calculated based on the “boundary meter”
2. Customers will be able to switch supplier in the standard way

Exempt sites manage all the electricity flows within their area and then usually have a “top up and spill” contract to manage any difference between actual demand and actual generation.  This allows them to import to and from the wider electricity grid.  Many exempt sites have sophisticated metering for all their customers and are able to monitor demand on a half hourly basis.

The electricity market requires small customers, such as households, to have a meter which records the quantity of electricity consumed over a period of time, but not when that electricity was consumed.  To turn this into half hourly data, a customer profile is applied in which a customer is assumed to consume electricity a particular proportion of energy in each half hour relative to their overall consumption.

While this works well over a large portfolio of customers, on small sites it can leave a significant difference between actually consumed electricity and quantities recorded in settlement.  Or in other words, your demand and generation on the site can match physically in a half hour period, but settlement will deem you to be out of balance because the generation and aggregate profile consumption did not match.

License light sites will be exposed to the full requirements for customer switching, although it is worth noting that the Citiworks ruling has upheld the customer’s right to switch and so it will also become a requirement for exempt sites.  It also adds a myriad of rules around issues such as customer charters, meter inspections, requirements to publish tariffs on price comparison sites etc, which exempt sites do not have to comply with.

As a result of all of these issues, license light will operate and contain a very different profile of revenues, costs and risks compared to exempt sites.

Will anyone offer terms?

Ofgem will not compel licensed suppliers to offer terms to license light parties.  Given that the electricity market has 6 main suppliers and only a few small independent suppliers, the pool for potential contracting partners is extremely small.

Although a 1,000 home scheme would be considered quite large in the context of housing developments, they are extremely small in the context of the scale of the large supplier’s customer base.  Their systems are largely automated and would require modification to manage the requirements of the license light parties.  As a result, the costs are likely to be high for a very limited return.  We would be surprised if more than 2 or 3 parties show significant interest in developing and signing an agreement.

What arrangements are required?

Any agreement is going to cover three key areas: submission of information; dealing with imbalanced electricity volumes; and credit terms.  An Ofgem document (pdf) sets out greater detail on some of the terms which will need to be put in place.

An agreement for license light services will require the fully licensed party to submit information on your behalf to the industry.  There are strict requirements about how information is submitted and within what time parameters, set out in the Balancing and Settlement Code (amongst the key industry code documents).  This means that the license light party will have to be able to respond rapidly and potentially provide IT systems which can interface in an automated way with their agreement counterpart.  This may well require a mini replication of the full IT systems as well as a detailed understanding of what the code requirements are.

In addition to suitable IT systems, a key part of the agreement will be imbalance charges.  Licensed suppliers are required to ensure that, for each half hour, generation and supply match.  If a party is not matched, then penalty prices apply.  These prices are calculated each half hour and depend on the costs incurred by National Grid in keeping the system balanced.  Imbalance prices, although generally reasonable, can become thousands of pounds per MWh – many times above the cost of own generation.  A counterparty will look to pass back through any imbalance risk and it may not be possible to share in any of the portfolio benefits that the large suppliers have.

With potentially large volumes of costs associated with imbalance and other such charges, any agreement will have credit requirements.  The ESCO will have to provide suitable credit terms under the agreement.  Generally, credit is a significant issue for suppliers and we would expect to see credit being a difficult issue to negotiate.

What will it cost?

We would expect the first agreement, if produced from scratch, will cost tens if not hundreds of thousands of pounds of legal fees.  In addition to that, most likely any agreement will require a significant investment in IT and staffing.  Your counterparty will then require ongoing payments for services used.  Having investigated, we are doubtful that the costs of being licensed light will be significantly different from fully licensed.

So how does this go forward?

Changing the license condition is the straightforward part of the process and provided that there are no significant objections, Ofgem will be able to make the necessary license condition changes to legally allow a license light regime to exist.  Ofgem plans to form a working group to progress license light and also plans to monitor the market for two years to see if license light provision develops organically.  Although technically possible in 2009, license light is unlikely to be a practical reality for at least another few years.

Distribution charges are paid by both generators and customers connected to the distribution network.  Charges vary by customer type and distribution zone.  Ofgem, the electricity and gas regulator instigated a review of distribution charges to better reflect distributed energy.

Originally, OFGEM proposals were to include a “short haul” tariff to bring in cost reflective pricing.  This would have reduced the charges paid by distributed energy schemes connected to a distribution network (not a private wire scheme) to reflect the fact that generation and consumption occur locally.  It would also have required cost reflective generation charges for distributed generation, which in some areas would have allowed generation to be paid (rather than pay) to be connected.

However, the package of changes was rejected by a number of distribution license holders and so changes cannot be implemented.  Ofgem is currently consulting on whether to send the proposals to the Competition Commission.  New proposals with cost reflective pricing for distributed energy are now at least two years away.