Utility engagement with DG gathers momentum1 February 2010
The benefits to many utilities of distributed generation used to be unclear, its economic value was often uncertain. Today, there is growing evidence that some utilities see potential value in DG, and are increasingly looking for ways to deploy it effectively. A new white paper from decentralised energy consultants Delta Energy and Environment (www.delta-ee.com), summarised here, explores case studies of utilities engaging with DG and the value this brings to their business. It also considers whether these examples signal a wider trend – or will prove transient.
Ten years ago, distributed generation (DG) had little to offer to many utilities. Engagement usually took place on the basis of specific policy incentives, with subsequent disengagement when these were withdrawn. Today, however, there is growing evidence that utilities are engaging with DG on the basis of a range of emerging drivers that can increase its value for utility businesses. As a result there are now a range of examples around the world of utilities using DG to improve their long-term business performance.
There is a business case for distributed generation across several parts of the utility business:
• Retail – some utilities can compensate for the prospect of falling commodity revenue by selling DG technologies to customers, and providing an array of energy services alongside.
• Congestion relief – some distribution network operators use dispatchable distributed resources to reduce network loads, especially during system peaks.
• Trading and load balancing – some utilities control DG to dispatch at peak demand, and sell the high value electricity on the energy exchange or balance supply and demand, eg to accommodate intermittent renewables.
Retail: differentiating your offering
In a competitive market environment, electricity utilities can offer DG technologies to customers to differentiate their offering from competitors, while gas utilities can use CHP to protect retail sales from encroachment by electric heating. Both can choose from a growing menu of new DG technologies that are emerging in the market, due to improving DG performance and falling product costs.
Customer retention is already an important driver for DG, but income from technology sales and services could substitute declining commodity sales in the future, as energy efficiency measures reduce demand and enable demand side management.
In Japan, gas and electricity companies have battled over customers in the domestic energy market for years (Figure 1). Electricity utilities promote the ‘all-electric house’, using grid electricity with electric heat pumps for space and water heating. They are also investing heavily in electric vehicle development to grow their commodity business in the future. Gas utilities have supported the development of fuel cells for residential CHP applications, aiming to protect their gas sales in the domestic heating market, and capture part of the power market. They are investing in fuel cell cars and natural gas derived hydrogen fuelling stations to enter the transport market.
Osaka Gas, for example, one of the most active Japanese gas utilities, has partnered with Eneos Celltech (ex-Sanyo) and Toshiba to develop a fuel cell based micro-CHP system. It launched the ENEFARM unit in spring 2009, and expects to exceed its 1000 unit sales target in the first year.
Meanwhile, Tokyo Electric Power Company (TEPCO) has partnered with Denso, resulting in the EcoCute, the first residential CO2 heat pump in the world.
As the R&D partnerships delivered commercial products, the utilities started developing attractive customer propositions to drive early uptake. Financial incentives are by far the strongest element of these. TEPCO for example, offers peak export tariffs for PV of around ¥30 per kWh, while retail rates are roughly ¥20 per kWh (r0.15). Gas utilities offer discount gas tariffs, as Osaka Gas does for customers installing the ECOWILL gas-engine micro-CHP system. This results in an annual benefit of ¥46 000 per year (r340), so that the extra costs of ¥262 000 (r1940) over a conventional water heater is recovered in 5.7 years (Figure 2).
Network congestion is an increasing challenge for network operators as peak demand grows. Building additional grid capacity is expensive everywhere, and spatial constraints make it near to impossible in some places, like Manhattan.
Many network operators have therefore started assessing opportunities for alternative solutions, eg demand response and DG to ease the load on strained networks by producing power for on-site consumption, reducing demand on the grid.
Take the case of the city of Everett in Massachusetts. This has experienced rapid load growth, so that the two 23 kV supply lines are now barely capable of meeting the summer peak load. National Grid, the local network operator, therefore started a congestion relief pilot in 2006 to evaluate the business case for using DG to displace network load, combined with demand response and energy conservation.
To drive the uptake of DG, National Grid started offering free energy audits to customers to identify opportunities to install such technologies. Project grants financed feasibility studies, as well as installation subsidies. A total of thirteen PV and biomass systems are now being deployed, delivering 510 kW capacity, equivalent to 1.8% daily load relief to the distribution network. National Grid expects to enable another 140 kW of DG, which, together with 3% energy conservation, adds up to a 6% drop in peak demand (Figure 3).
Trading, demand management and load balancing
In liberalised energy markets, electricity trading can be an important source of revenue for utilities, for example by scheduling generation to coincide with peak power demand and prices. DG can be a source of such value if it can be dispatched directly by the utility’s trading desk.
Not all DG technologies are suitable for electricity trading and load balancing - they need to be directly controllable. This excludes intermittent resources, such as wind, while the trading value of continuous generators, like run-of-river hydro is also limited.
Back-up generators are a commonly used dispatchable resource, and examples of such aggregators include Flexitricity in the UK and Portland General Electric in the USA. CHP plants are also suitable, where generation can be decoupled from heat demand by using a heat store.
In the Netherlands, Essent has developed dispatchable CHP gas engine systems with its horticultural customers since the 1990s, allowing it to increase its generation rapidly at peak times. An on-site heat store ensures that farmers can heat greenhouses when needed, independently from power production.
Essent now operates over 3000 such installations, all controlled from a central dispatch centre. The units run to a pre-programmed schedule, but Essent can intervene remotely at any time. The business unit responsible for these systems now has an annual turnover of r15 million.
Horticultural customers have proved a fertile customer group for dispatchable DG because energy accounts for a large part of their costs and government subsidies have provided additional incentives. Essent offers different business models and bespoke contracting arrangements to share risks and revenues with customers. This co-operative approach has helped secure customer buy-in and strengthened client relations.
In Germany, EWE is trialling DG as a way of helping to balance supply and demand in a system expected to have a growing share of renewables.
The utility’s eTelligence pilot project in the city of Cuxhaven is exploring the use of DG and controllable loads to provide power during peak times and fill valleys during off-peak. It has created two networks linking all large loads and generators, one physical, through the grid, allowing balancing of supply and demand, and one virtual, a dedicated IT network enabling all loads and generators to exchange information, allowing EWE to send price incentives for customers to switch off loads and free up capacity on the physical network.
EWE’s distributed generators include biomass and PV plants, while commercial customers provide the flexible loads. For example, a cold store in Cuxhaven has learned to ‘play’ the market by switching on and off its freezers, reducing energy costs.
Sourcing electricity from DG is part of EWE’s future vision. It aims to own and control fuel cell systems in the houses of residential customers. It is preparing for this market by entering into long-term heat supply contracts which give it ownership of boilers, allowing it to replace these with fuel cells over time. Initially, EWE would use these systems to reduce the demand of individual houses at peak times – effectively a scaled-down version of eTelligence. If fuel cell production costs fall sufficiently, EWE will be able to supply electricity at a lower cost than through the grid, unleashing a large resource of cheap controllable energy.
Pilots, trials and commercial strategies
The projects mentioned above range from ‘testing the water’ to long-term commercial strategies:
• National Grid’s congestion relief programme is a pilot, as the heavy upfront investment to engage customers is not being recovered yet. The company is currently evaluating the benefits for its grid operation, expecting to have a clearer understanding of the long-term business case towards the end of 2009.
• EWE’s use of distributed resources to provide both energy and power has benefited from public-sector funding, and is not currently viable on purely commercial terms. However, the company expects that the economics will improve as intermittency on the grid grows and distributed energy technology costs fall. EWE appears to be in it for the long-run.
• Deploying DG as a resource for trading is already fully commercial. For Essent, dispatching its gas engine CHP assets based on market signals is not merely financially attractive, but is essential, as operating them outside peak hours would be unprofitable.
• Investing heavily to drive DG uptake is a commercial necessity for some Japanese utilities.
In the future the value of DG to utility businesses is expected to grow. And alongside this, questions that energy companies will increasingly consider when developing their approaches to DG might include:
• How will the costs and performance of technologies develop, and which can be most successfully deployed?
• How can DG, demand management and smart grid initiatives interact to create the best results for utility businesses?
• Will the expansion of nuclear power and CCS shrink the market for DG, or drive its use for flexible back-up?
• To what extent can DG be used alongside the charging infrastructure for electric vehicles?
• What carbon targets will countries adopt, and which governments will incentivise DG to achieve these targets?
A diversity of approaches
Utility business models for DG are likely to vary with company structure, strategy and market environment. Some energy companies will stick with what they know best – generating electricity in large plants and selling this on a commodity basis to customers. Growing numbers will look to differentiate and provide DG alongside energy services; or, for example, develop DG alongside smart grid infrastructure and IT systems to drive the uptake of electric vehicles.
Even within a single national market, companies are choosing different solutions. In the UK, Centrica is driving micro-generation, while Scottish Power has, for now, decided to deploy large renewable resources instead. Competition will only enhance diversity as utilities strive to differentiate their offering.
All in all, a new trend towards utility engagement in DG is now becoming clearer. We expect this to gather some momentum as new drivers of utility performance strengthen. The question is increasingly shifting from whether using distributed generation makes sense for utilities, to how best to deploy it.