As the alternatives impact only the proposed 400kV network, any variation in cost is estimated from this base cost – to evaluate which, use has been made of the more recent introduction of life-cycle transmission cost structure estimating  which takes account of fixed and variable costs over the asset life depreciated over 40 years . This base cost is estimated to be in the region of £330m (vii).
The cost for a suitable sub-sea HVDC interconnector is arrived at by evaluating several similar UK project proposals in various stages of execution (viii) to arrive at an estimate for a 211km, 1,000MW link of £620m which suggests that earlier calculations  for a sub-sea alternative to landbased 400kV OHLs have fallen significantly since 2012 due to a number of factors such as: a) experience gained in the use of this technology, b) technology costs have fallen due to competition entering the market and c) volume effects.
The undergrounding of the alternative 132kv network is estimated at £2.0m/km based on underground cable costs of £1.3m/km for a 4-circuit 576MW capacity  together with £0.7m/km to accommodate switchgear and transformers costs etc., resulting in a figure of £262m for this option. Consequently, the additional cost of this alternative is estimated to be in the region of £552m (= £620m + £262m – £330m). If only half the 132km route is undergrounded the additional cost falls to
The second alternative is based on retaining the 400kV network but undergrounding all – if this were technically possible, which is unlikely – or only part of it and here a figure of 50% is assumed, i.e. a maximum of 65km, typically in several sections. The additional cost in this case is in the order of £508m.
As both alternatives require a similar additional capital investment of around £500m this figure is used below to arrive at the additional cost to household electricity bills .
Ofgem, under price control mechanism, TIIO-T1, limit transmission operators to recovering costs and earning a reasonable return on capital subject to delivering value for consumers, behaving efficiently and achieving targets . For each operator this return will be slightly different depending on their level of gearing and, in the case of SPEN, their weighted average cost of capital (WACC) for 2013-2021 under TIIO-T1 is 4.91% pre-tax. In addition transmission assets are depreciated over 40 years  which implies an amortisation rate of 2.5%.
The implication of this is that an additional £500m of expenditure represents an additional cost to the consumer of 7.41% (= 4.91% + 2.5%) per year of the additional capital cost which is £37.05m per annum.
As Scottish Power Energy Network’s revenue from transmission and distribution was £1135m in 2014  the additional annual premium to be recovered from SPEN’s electricity consumers represents 3.26% (= £37.05m/£1135m * 100%) of revenues. Further to this the average annual household electricity bill in the UK in 2014 was £592  and as transmission costs represent 4% of a consumers electricity bill transmission costs for the average household represents £23.68 per annum.
The additional annual premium to consumers that enables SPEN to recover their costs and make a return on the additional £500m therefore equates to £0.77 per household (= 3.26% * £23.68). However, because distribution charges account for around 16% of consumers electricity bills  the additional household premium will increase to around £3.85per annum (= 5 * £0.77). In summary, therefore, and based on the above estimates a sub-sea cable option together with reducing the supergrid to 132kV and undergrounding, or alternatively maintaining the super-grid and undergrounding up to 50% of the route will cost the typical household in the order of £3.85 per annum in addition to what they currently pay for their electricity.
Having established the order of cost the question then becomes: “Is the customer willing to pay this additional premium to protect the visual amenity and their environment in general?” The following section examines this proposition.