An important part of our project is determining the financial feasibility of our concept. Offshore renewable energy technology is still in its infancy, with the large costs associated a principal barrier. We identified two major costs of offshore energy generation, cables and foundations, which we believed could be significantly reduced with our hybrid concept.

Financial analysis was split into three main sections:

  • Calculating the Target Levelised Cost of Energy
  • Comparison With Existing Offshore Technology
  • Sensitivity Analysis

A cost comparison between our hybrid concept, and individual systems of the same capacity will be carried out to determine if our design is viable. We will investigate how much our system would need to cost to compete with separate technologies, and finally perform a sensitivity analysis on our system.

Target Levelised Cost of Energy

The Levelised Cost of Energy is an important factor when performing a financial analysis. It gives the total cost of the electricity produced over a project lifetime. In other words, the LCOE is the minimum price at which electricity must be sold in order to be profitable. The tidal technology can be seen to be profitable due to the high government incentives. Without these, tidal technology would currently struggle but as technology matures, will become more economically viable. Figure 1 below shows the equation used to calculate the LCOE [1].

Levelised Cost of Energy Equation
Figure 1: Equation for Levelised Cost of Energy

 

  • AEPnet = net average annual energy production (MWh/MW/yr)
  • d = discounting rate
  • T = effective tax rate
  • PVdep= present value of depreciation

Contracts for Difference

As part of the Electricity Market Reform set out by the UK government in 2013, a scheme called “Contracts for Difference” has been implemented. This involves the government topping up the difference between the electricity price and a “strike price” to guarantee clean electricity providers a steady and generous price for their electricity over the duration of a 15 year contract.

Suppliers bid in an auction for these contracts which start at the strike price until the lowest bid. This price will then be guaranteed for the electricity irrespective of the electricity price. We have assumed that the maximum strike prices will be paid to HOWaT although in reality they would be slightly lower. We have also assumed we would sell electricity at the strike price over our 20 year operating period rather than the 15 year period specified in the contracts.

The strike prices paid for wind and tidal stream generation are currently [2]:

  • 10.5p/kWh for wind
  • 30p/kWh for tidal

From these strike prices it is possible to calculate an aggregated strike price for our system. This resulted in a value of 14.6p/kWh. In order to be profitable HOWaT must produce electricity at a lower cost per kWh than this value.

These incentives are pivotal to the development of emerging technologies such as tidal current. Without the Contracts for Difference scheme, HOWaT would need to produce electricity at a much lower cost in order to be justifiable.

Comparison with Existing Offshore Technology

 

Offshore wind is beginning to become an established and mature energy generation technology. Soon it will be a strong financial investment even without high incentives. In this section we will compare the financial aspects of our system with existing wind technology.

The main area to compare is the Levelised Cost of Energy. Several Assumptions were made in our calculations. These were as follows:

  • Electricity will be sold at the strike price over the entire 20 year operational lifetime as opposed to the 15 year period specified in the Electricity Market Reform
  • The availability (percentage of time generating energy over lifetime) of both wind and hybrid devices is taken to be 92%
  • The hybrid capacity factor was assumed at 0.4
  • The savings made on the tidal system when attached to wind were estimated at 36% of capital costs
  • The operations and maintenance costs of our system is equal to the sum of the relevant wind and tidal current costs
  • Discounting Rate for all offshore technologies = 10% [3]
  • Fixed Charge Rate = 9.8% [4]
  • Our estimated CAPEX for HOWaT was inflated by 20% to account for costs of developing the technology and any unknown miscellaneous costs which may be incurred
  • Exchange rates are accurate at the time of publication of the relevant data

 

Wind Turbine and HOWaT CAPEX

 

Wind

We estimated Capital costs for offshore wind energy by finding costs for foundations, electrical infrastructure, wind tower, nacelle, and rotor and then estimating the remaining costs from a cost breakdown provided by the NREL. This can be seen in Figure 2 below [5].

NREL Cost Breakdown
Figure 2: NREL Capital Cost Breakdown

 

The estimated manufactured costs for the wind turbine were taken from a Crown Estate study (A Guide to Offshore Wind) and are shown in Figures 3 and 4 below. These costs give an estimated total cost of the wind turbine nacelle, rotors, and tower as £5 million [6]. These costs will be subject to further cost reductions as technoogy improves.

 

 

Nacelle Capital Cost
Nacelle £2,500,000
Nacelle Bedplate £100,000 - £120,000
Main Bearing £60,000 - £80,000
Main Shaft £100,000
Gearbox £700,000 - £1,000,000
Generator £200,000 - £250,000
Power Take-Off £400,000
Control System £70,000
Yaw System £100,000
Yaw Bearing £40,000 - £50,000
Nacelle Auxiliary Systems A few % of larger costs
Nacelle Cover £60,000 - £90,000
Small Engineering Components Small
Fasteners £10,000 - £15,000
Condition Monitoring System £10,000 - £20,000
Rotor and Tower Capital Costs
Rotor £1,200,000 - £1,500,000
Blades £250,000 - £350,000
Structural Composite Materials Half the cost of blade
Blade Root 20 % Blade cost
Lightning Protection Low Cost (Approximated)
Hub Casting £80000
Blade Bearings £40,000 - £50,000
Pitch System (Electric or Hydraulic) £100,000 - £150,000
Spinner £20,000 - £30,000
Rotor Auxiliary Systems £3,000 - £10,000
Fabricated Steel Components £100's to £20,000
Tower £1,000,000

 

The foundation costs for wind and hybrid technology were calculated by using a cost per tonne for the monopile and transition piece, using our structural dimensions. This price was estimated from a Crown Estate publication [7]. Our obtained value of £1.17m for a single monopile and transition piece aligned well with estimated costs from literature.The calculations used to obtain these values are shown in our financial analysis Excel sheet. This contains further details on all calculations performed in the section.

Financial Analysis Spreadsheet Download

 

HOWaT

For our hybrid system, the Capital costs for wind were assumed to be the same as above, however, the additional tidal CAPEX and reinforcement is also accounted for. Furthermore, transmission costs were included in calculations to take into account the increased transmission costs associated with additional generation.

Tidal costs are difficult to estimate as there are no existing commercial producers of tidal current energy. Our CAPEX figures are taken from a study by Black & Veatch and NREL [8].

These were then modified to account for the shared foundation and cable costs associated with the hybridisation. The graph (figure 5) shows an estimated CAPEX cost breakdown for tidal current energy. (REF Carbon Trust) It was assumed that 36% of these costs (15% from structure, 13% from off-board electrical equipment, and 8% from installation).

Using this information the Capital costs were estimated to be £2.37m/MW for the tidal component.

Tidal CAPEX Breakdown
Figure 5: Tidal CAPEX Breakdown
Tidal CAPEX Savings
Figure 6: Tidal CAPEX Savings

 

 

Table 1 - Tidal CAPEX Savings
Capital cost of normal Tidal turbine ($/MW) $5,880,000
Applying exchange rate (£/MW) £3,704,400
Applying Cost Reductions (£/MW) £2,370,816
Capital Cost for 2MW System £4,741,632

 

Transmission costs were calculated using data from Catapult ORE and Black & Veatch [9] [10]. Total capital costs including substation and transmission lines were found to be £5.055m.

Additional reinforcement was required in order to maintain the structural integrity of our foundation with the additional loads associated with tidal technology. More details can be found in structural analysis.

With a monopile thickness increasing from 70mm to 85mm, a further cost of around £150,000 was required. This equates to 13% of added cost which does not have a major effect on the overall analysis.

The following costs were estimated from the NREL wind capital cost breakdown graph (figure 2)

  • Installation (8%) = £1.25m
  • Miscellaneous (decommissioning, engineering and management, development) (8%) = £1.25m
  • Contingency (9%) = £1.35m

 

 

Wind and HOWaT OPEX

 

Wind

For the Operating expenditures of wind technology, a value was assumed from NREL's 2014 Cost of Wind Energy Review [11]. This was deemed an appropriate source as our system is based on NREL's 5MW reference turbine. The OPEX of a wind farm tends to account for between 20% and 30% of total system costs [12].

HOWaT

The OPEX for tidal technology was estimated from the Black and Veatch/NREL study alluded to previously. The given value was £124,740/MW/yr. It was required to combine this value with the wind OPEX value to find a system OPEX cost of £92,500/MW/yr.

This value is accurate for a larger scale but to account for higher relative operational costs at our lower scale, a multiplying factor of 1.3 was applied to give a hybrid OPEX of £120,200/MW/yr.

LCOE Comparison

Our Levelised Cost of Energy could then be calculated for each system using the earlier equation shown in figure 1.

Our calculated LCOE values were:

  • Wind = 8.6p/kWh
  • Hybrid = 14.1p/kWh

The findings of our comparison highlight the dependency on government incentives for our systems viability. Figure 7 below plots the LCOE and strike prices for offshore wind and HOWaT against each other. The next graph, Figure 8, examines the difference that lowering the strike price received for our electricity would make to its profitability.

Wind vs Hybrid
Figure 7: Wind vs Hybrid LCOE Comparison
Wind vs Hybrid Modified
Figure 8: Modified Wind vs Hybrid LCOE Comparison

 

 

Sensitivity Analysis

To evaluate the robustness of our concept, a sensitivity analysis has been performed. This will examine the effect that small changes will have on the overall economic feasibility of the system. The areas to be analysed include: government incentives and electricity price, distance from shore, capacity factor, fixed charge rate, and size of array.

The analysis will see if our system will have economic feasibility even if several circumstances change. If our technology can remain competitive under these altered parameters then it is likely to be a successful technology.

We have examined the following parameter changes:

  • Distance to shore – 6km, 8km, 10km, 20km
  • 1-10 turbines
  • Capacity Coefficient 30%, 35%, 40%, 45%
  • Incentives capped at £105/MWh rather than £146/MWh
  • Fixed Charge Rate – 9.5%, 9.8%, 10%, 10.5%

 

Sensitivity Capacity Coefficient Change
Figure 9: LCOE with changing Capacity Factor
Sensitivity Shore Distance Change
Figure 10: LCOE at changing distances to shore

Sensitivity Fixed Charge Rate
Figure 11: LCOE at changing fixed charge rates
Sensitivity Incentives Change
Figure 12: Modified Wind vs Hybrid LCOE Comparison

 

 

As the number of turbines increased the LCOE of the array decreased. This was initially a substantial decrease but the LCOE began to plateau as the number of turbines grew. This was caused partly because of an assumed constant OPEX which would in reality decrease with a larger array, thus decreasing LCOE further.

At larger scale however, additional export cable and substation costs would be incurred which would result in there being an optimum array size just before this point. Further analysis would be required to obtain this information.

When the distance to shore was changed, a significant increase in price with increasing distance was seen at lower numbers of turbines. However, this change was far less apart with a larger array. The nature of tidal currents means that HOWaT systems would not tend to be very far from the shore in any case.

Energy output from a generation device will always be heavily influenced by capacity coefficient. Depending on the size of turbine used and available resource, HOWaT capacity coefficients could be significantly changed in different locations. This has a substantial effect on the LCOE. A location and resource must be analysed carefully in order to achieve a viable energy cost.

The volatile nature of politics leads to uncertainty of government incentives. The effect of reducing these incentives is clear to see in figure 12. Lowering the costs of both tidal and wind generation is of paramount importance as relying purely on incentives is risky.

For LCOE calculations, the fixed charge rate, a variable in the LCOE equation, has been altered and the effects were examined. The resulting graph shows that only slight changes in LCOE were observed with different fixed charge rates

 

Payback Period

An important factor in determining the cost-effectiveness of a project is the time it takes to pay back an initial investment. A discounted payback period is used to determine at what point the initial investment would be paid back. Initial capital expenditure as well as early operations and maintenance payments are considered. The payback period for 10 HOWaT systems was found to be roughly 16 years. This does not represent the strongest investment, however it does show the systems viability. With improvements to cost, this period will lower and a return will be seen on initial investment.

The graph below shows the cumulative discounted cash flow. This shows the year at which the break-even point is reached and quantifies the profits after this point. Year 1 in the graph is effectively year 0 when the capital investment has been made but no energy production has occurred.

Financial Payback
Figure 13: Project Payback

Financial Conclusions

Our financial analysis was undertaken to evaluate the feasibility of HOWaT under current conditions and in the future. Some optimistic assumptions have been made in estimating costs, however care was taken to ensure their accuracy as far as reasonably possible. In future research, it would be useful to investigate the potential for even larger arrays and how this would affect the financial aspects of the project. Adjusting and refining the HOWaT design could lead to additional cost reductions. Another consideration would be the effect of hybridisation on operations and maintenance costs. It remains to be seen whether costs would be higher or lower than the sum of tidal and wind parts. This could be an important factor in future viability and could only be established through the implementation of our system.

The main points to take away from this analysis are as follows:

  • Offshore wind energy is currently more viable
  • Government incentives are pivotal in future tidal development
  • Cost improvements to tidal technology are also imperative
  • Financial feasibility may differ significantly depending on location
  • Sharing transmission and foundations allow large savings on HOWaT’s capital costs
  • Realistic future potential for HOWaT
  1. Moné, C. Stehly, T. Maples, B. Settle, E. NREL 2014 Cost of Wind Energy Review
  2. UK Government - Department for Business, Energy, and Industrial Strategy
  3. Oxera - Discount Rates for Low-carbon and Renewable Generation Technologies
  4. Moné, C. Stehly, T. Maples, B. Settle, E. NREL 2014 Cost of Wind Energy Review
  5. Moné, C. Stehly, T. Maples, B. Settle, E. NREL 2014 Cost of Wind Energy Review
  6. Crown Estate (2010) A Guide to an Offshore Wind Farm
  7. Crown Estate (2011) Offshore Wind Cost Reduction Pathways Study
  8. Black & Veatch (2012) Cost and Performance Data for Power Generation Technologies
  9. Catapult Offshore Renewable Energy (2016) Transmission Costs for Offshore Wind - Final Report
  10. Black & Veatch (2014) Capital Costs for Transmission and Substations
  11. Moné, C. Stehly, T. Maples, B. Settle, E. NREL 2014 Cost of Wind Energy Review
  12. Renewables Advisory Board (2010) Value Breakdown for the Offshore Wind Sector