Energy and Climate Change CommitteeSupplementary written evidence submitted by Engineering the Future

SPEAKING NOTES PROFESSOR TIM BROYD 11.15 THURSDAY 10 JANUARY

Part 1: Energy Infrastructure

Advantages and disadvantages of hydro generation:
1(a) How can intermittency of tidal power be overcome via engineering interventions?

There are two approaches to managing the intermittency of tidal range power:

within the scheme itself, and

within the wider power system.

Within the scheme itself

Opportunities to hold back tidal flows can extend (and even out) the generation period to allow generation for more hours in the day, and/or to delay generation to times of greater demand. We understand the Corlen Hafron scheme has explored this in some detail, though this should be subject to third party review as part of any case for Government support.

Whilst this will improve the generation profile it will not allow full control of generation over the 24 hour daily cycle.

Within the wider power system

There are three main ways of managing intermittency—supply management, demand management, and storage. These would need examination and optimisation in the context of the whole UK electricity system. Overall the extent to which the intermittency issue will be problematic and costly will depend on how far and how fast other Government policies around electrification of demand are progressed, and the success in delivering the smart grid necessary to support these policies.

The “conventional” supply-side way is to provide higher levels of reserve or back-up generation so that any shortfalls can be quickly met and any excesses are managed by constraining generation output or exporting/importing electricity to/from another country’s system using interconnectors.

The mix and flexibility of other connected generation will be important here with generation becoming less flexible. Nuclear plant is relatively inflexible, and wind and solar plant have intermittency issues of their own. Gas and coal fired plant can be specified to be more flexible (but this needs to be engineered into the design and there are trade-offs between flexibility and thermal efficiency. It is currently unclear the extent to which carbon capture and storage equipment would impact flexibility.

On the demand side, there are likely to be emerging classes of demand that could offer flexibility within the 24 hour cycle, notably the charging of electric vehicles, and the replacement of gas heating boilers by electric heat pumps. The extent to which these could be integrated with the time varying output of a Severn Barrage would need further study, but in principle these demands could be varied to match the project’s output. To do this would require a full smart grid implementation, making even stronger the case the IET and others have been arguing consistently for some years that the planned smart meter rollout for the UK be made smart grid ready.

Where economic, storage has a role, described in 1b below.

1(b) What energy storage technologies are available? What R&D is being undertaken in this area?

The full range of energy storage technologies, and current developments, are usefully summarised in the IET briefing document published earlier this year. (See table appended) http://www.theiet.org/factfiles/energy/energy-storage-page.cfm

However, it should be emphasised that a barrage scheme is itself a form of short term energy storage at the largest levels of power and energy currently engineered. It is therefore improbable that a complementary large scale energy storage system associated with a barrage is economically viable or even desirable.

A large number of smaller storage devices distributed through the electricity network would enable more effective use of barrage production, although their economic value would need careful assessment versus supply and demand management alternatives, and other forms of generation than a barrage.

The whole storage area is subject to massive R&D effort worldwide from both companies and governments, with the aim to reduce costs and improve round trip efficiencies.

1(c) Cost effectiveness of a tidal barrage: Are we able to say whether the Hafren estimates are accurate?

The generation costs stated in Corlen Hafren’s evidence are £160/MWh for the first thirty years, and £20/MWh thereafter, though the evidence does also cite non-electricity revenue opportunities such as flood protection which would need further exploration.

Whether a strike price of £100/MWh could be sufficient to support this cost base would also need further exploration.

£160/MWh is substantially less than historic estimates for Severn Barrage designs, and we understand have been driven by consideration of novel turbine types together with a re-appraisal of all aspects of the scheme’s design and duty. We are not at this stage convinced that the capital cost reductions are sufficient to support a generation cost of £160/MWh for the first 30 years of the scheme, especially when the full range of total capital costs including financing costs are taken into account. We have not seen sufficient information to allow an authoritative independent review of the pricing, and would recommend Government commissions such a review from an independent engineering firm not previously involved before it considers any further investigations.

After the capital committed for construction has been paid off, which we would expect to take place over the first 30 years, the marginal costs of continuing generation should be small. We would expect these to comprise on-going maintenance of the asset, employment costs for staff, insurance, grid connection, rates and similar charges. Review is again needed, but £20/MWh in 2012 terms does not seem unreasonable as a first view.

Integration of Hydro to existing energy system:
1(d) What are the transmission requirements?

Due to its high output—it would be equivalent in MW terms to around four new nuclear reactors (though with much less energy production owing to its lower load factor)—the barrage scheme would need to feed directly into the high voltage transmission system. The grid designed in the 1940s to connect power stations located near coal fields to centres of high demand is not necessarily in the right places to connect in renewable energy. As new power stations are built in different areas, new lines and upgrades to existing parts of the grid will be required.

The grid costs are not borne by the generation developer, but the developer is liable for these costs if the project is cancelled and the costs and investments become redundant and stranded. To cover this liability, a generation development is required to provide the appropriate financial securities, which will increase over the construction programme.

National Grid was asked in 2010 to consider how the DECC scheme studied at that time could be connected to the grid and whether this would require any new infrastructure or uprating of existing infrastructure. We understand the Corlen Hafron scheme has a lower maximum output than the DECC scheme, and as such National Grid’s conclusions would need re-evaluation to a degree.

The study by National Grid1 concluded that for a Cardiff-Weston barrage considered by DECC the optimum solution was for an equal amount of power (4.32 GW) to be taken off on the English and Welsh sides. It identified three options—one with no transmission cables across the barrage and two with cables (one AC and one DC). All have similar costs of between £2.25 billion and £2.35 billion, though the option with no cable across the barrage could take at least three years longer to complete because that option may need a 125 km new overhead line to the south coast. All options would require major new transmission lines with associated public debate over their environmental impact.

The study by National Grid also assumed greater levels of international interconnection and use of smart technology (Smart Grid) to manage demand and power flows.

The study found that in principle it should be possible to accommodate this level of tidal generation. However, there were concerns over both system stability and electrical inertia that would require further detailed study and might require significant further investment to resolve.

January 2013

Annex taken from IET Briefing on Electricity Storage, 2012

Table 1

COMPARISON OF STORAGE TECHNOLOGIES

Technology	Typical Rated Capacity (MW)	Nominal Duration(1)	Cycle Efficiency (%)(2)	Technology Maturity	Usual/Anticipated Scale
Mechanical
Pumped Hydroelectric Storage	100–5,000	1—24+ hrs	70–87	Mature & Commercial	Large Grid
Compressed Air Energy Storage	50–300	1—24+ hrs	70—89	Commercial	Large Grid
Cryogen-based Energy Storage	10–200	1—12+ hrs	40—90+	Early Commercial	Grid/EV(3)/Commercial UPS(4)
Flywheel	0.4–20	1—15 mins	80—95	Demo/Early Commercial	Small Grid/House/EV
Electro-mechanical
Hydrogen Storage & Fuel Cell	0—50	Seconds—24+ hrs	20—85	Demo	Grid/House/EV/Commercial UPS
Battery—Flow	0.03–3	Seconds—10 hrs	65—85	Research/Early Demo	Grid/House/EV/Commercial UPS
Battery—Lithium	1—100	0.15—1 hr	75—90	Demo	Grid/House/EV/Commercial UPS
Battery—Metal-Air	0.01–50	Seconds —5 hrs	~75	Research/Early Demo	Grid/House/EV/Commercial UPS
Battery—Sodium Sulphur	0.05–34	Seconds—8 hrs	75—90	Commercial	Grid/House/EV/Commercial UPS
Battery—Nickel	0—40	Seconds—hrs	60—90	Early Commercial	Grid/House/EV/Commercial UPS
Battery—Lead-Acid	0—40	Seconds—10 hrs	63—90	Mature & Commercial	Grid/House/EV/Commercial UPS
Primary
Superconducting Magnetic Energy Storage	0.1–10	Milliseconds—seconds	90—97+	Early Commercial	Small Grid/Commercial UPS
Supercapacitor	0—10	Milliseconds—1 hr	<75—98	Early Demo	Small Grid/House/EV

(1) The typical period that the technology can maintain its rated output from a fully charged state.

(2) The proportion of the energy used to charge the device that can will be returned to the system.

(3) EV = Electric vehicle

(4) UPS = Uninterruptible Power Supply

(Source: All data sourced from “Pathways for energy storage in the UK”—Centre for Low Carbon Futures)