Offshore Wind AR7 Prices vs “Firm” Offshore Wind + BESS: Quantitative Analysis and Comparison to SMR.

Headline insight: Todays AR7 offshore wind auction has locked in very competitive ~£91/MWh CfD prices for energy that is inherently intermittent.​ Once sized to provide quasi‑firm power (e.g. 20 hours/day) using transmission‑scale BESS at today’s UK costs and a 10% real WACC, the incremental cost of storage alone is of the order of £65–70/MWh. That implies an all‑in “firmed” offshore‑wind‑plus‑BESS cost of roughly £155–160/MWh in 2024 prices for 20‑hour availability, and ~£170/MWh for strict 24/7 baseload, before accounting for multi‑day lulls.

This is broadly more expensive than new UK nuclear on a firm‑power basis, and well above the bare offshore wind CfD strike price.

1. Today’s Offshore Wind CfD Results (AR7)

The AR7 offshore wind auction results announced today can be summarised as follows:​

• Total capacity awarded:

  • 8.44 GW offshore wind and floating offshore wind (8.25 GW fixed‑bottom + 0.19 GW floating).​

• Strike prices (2024 prices):

  • Fixed‑bottom offshore wind – England & Wales: £91.20/MWh.​

  • Fixed‑bottom offshore wind – Scotland: £89.49/MWh.​

  • Blended fixed‑bottom average: £90.91/MWh.​

  • Floating offshore wind (Erebus, Pentland): £216.49/MWh.​

• Examples of large awarded projects:​

Project	Capacity (MW)	Region	Strike price (2024)
Dogger Bank South E	1,500	England	£91.20/MWh
Dogger Bank South W	1,500	England	£91.20/MWh
Norfolk Vanguard E	1,545	England	£91.20/MWh
Norfolk Vanguard W	1,545	England	£91.20/MWh
Awel y Môr	775	Wales	£91.20/MWh
Berwick Bank B	1,380	Scotland	£89.49/MWh
Erebus (floating)	100	Wales	£216.49/MWh
Pentland (floating)	92.5	Scotland	£216.49/MWh

Government and industry commentary emphasises that these prices are around 40% below the cost of new CCGT (~£147/MWh) and below current estimates for new nuclear (~£124/MWh) on an LCOE basis, for intermittent output.​

2. Load Factor Assumptions for AR7 Projects

There are three relevant reference points for capacity (load) factors:

1. Historical fleet averages (DESNZ / DUKES):DESNZ long‑term average load factors used for energy statistics:

   • Offshore wind: 38.1% (fleet average).​

2. CfD methodology assumptions for new build projects:DESNZ’s CfD methodology for delivery years 2027–2031 uses higher net load factors for new offshore wind, reflecting better sites and larger turbines. The methodology table gives:​

   • Offshore wind (new build): 49% net load factor (mid‑range assumption).

3. Project‑level communications:

   • Dogger Bank and similar next‑generation North Sea projects often cite ~50–55% expected load factors in their own collateral.​

   • Some Crown Estate/ScotWind developers use a 40.1% fleet average over 2021–23 as a conservative anchor when quoting “homes powered”.​

For the purpose of this exercise:

• Consider a 40% load factor example, which is a conservative but still realistic long‑run fleet value.

• DESNZ CfD modelling uses ~49% for new OW, which would slightly improve the storage economics but not change the qualitative picture.​

The calculations below therefore use:

• Base case: CF=40%CF=40% (conservative, transparent).

• With commentary on how using 49% would modestly reduce the storage premium.

  
  

3. Stylised Storage Model: From 40% Load Factor to 24/7 and 20‑Hour Supply

To make the storage maths tractable and transparent, adopt a binary stylised profile:

• Each MW of offshore wind is either:

  • Generating at full power (1 MW), or

  • Generating nothing (0 MW).

• The fraction of hours with generation is equal to the load factor cc.For c=0.4c=0.4, generation occurs 40% of the hours.

So, per 1 MW of installed offshore wind:

• Average daily generation:Eday=c×24×1 MWh=0.4×24=9.6 MWh/dayEday=c×24×1 MWh=0.4×24=9.6 MWh/day.

This is the “energy budget” we can distribute across the day using BESS.

3.1 Case 1 – Full 24/7 “Virtual Baseload” from 40% CF Wind

Objective: deliver continuous power 24 hours/day from 1 MW of wind, using storage.

Let:

• PbasePbase = constant power delivered to the grid (MW per MW of wind).

• For energy balance over the day:

  Pbase×24=Eday=9.6 ⇒Pbase=0.4 MW/MWwindPbase×24=Eday=9.6 ⇒Pbase=0.4 MW/MWwind

Under the binary wind model:

• Hours with generation: Hon=c×24=0.4×24=9.6 h/dayHon=c×24=0.4×24=9.6 h/day

• Hours without generation: Hoff=24−Hon=14.4 h/dayHoff=24−Hon=14.4 h/day

During “on” hours:

• Generation = 1 MW

• Demand (to grid) = Pbase=0.4Pbase=0.4 MW

• Surplus for storage = 1−0.4=0.61−0.4=0.6 MW

During “off” hours:

• Generation = 0 MW

• Demand (to grid) = 0.4 MW

• Battery must discharge at 0.4 MW

Storage sizing per MW of wind:

• Required discharge power:PBESS=0.4 MW/MWwindPBESS=0.4 MW/MWwind

• Energy to be stored (daily):Either from charging or discharging perspective:

  EBESS,24h=PBESS×Hoff=0.4×14.4=5.76 MWh per MWwindEBESS,24h=PBESS×Hoff=0.4×14.4=5.76 MWh per MWwind

• Effective storage duration:

  Duration24h=EBESS,24hPBESS=5.760.4=14.4 hoursDuration24h=PBESSEBESS,24h=0.45.76=14.4 hours

So, in this stylised world, making 40% CF offshore wind into 24/7 baseload requires, per MW of wind:

• 0.4 MW of BESS power capacity, and

• 5.76 MWh of BESS energy capacity

• i.e. a ~14.4‑hour battery.

This is already an extreme storage requirement – and it does not address multi‑day lulls, just intra‑day variability.

3.2 Case 2 – “Optimised” High Availability: 20 Hours/Day Firm Supply

Now aim for a more realistic target:

• Deliver constant power for 20 hours/day (e.g. “firm for most of the day”).

• Allow 4 hours/day where the portfolio is allowed to be short (served by grid or another resource).

Using the same binary 40% CF model:

• Generation hours: Hon=9.6 h/dayHon=9.6 h/day

• Non‑generation hours: Hoff=14.4 h/dayHoff=14.4 h/day

• Target firm‑supply hours: Havail=20 h/dayHavail=20 h/day

• Outage (allowed shortage) hours: 24−20=4 h/day24−20=4 h/day

To minimise storage:

• Always serve the load when the wind is blowing (i.e. for 9.6 h/day).

• Use the battery to extend the supply into an additional 10.4 hours (to reach 20).

• Leave 4 of the 14.4 non‑generation hours completely unserved by this wind+BESS block.

Let Pbase,20hPbase,20h be the constant power delivered during those 20 hours.

Energy balance:

• Total load energy per day = Pbase,20h×20Pbase,20h×20

• This must equal the total wind energy per day (9.6 MWh), so:

  Pbase,20h×20=9.6⇒Pbase,20h=0.48 MW/MWwindPbase,20h×20=9.6⇒Pbase,20h=0.48 MW/MWwind

Storage balance:

• Charging: in generation hours, surplus to storage = 1−Pbase,20h=1−0.48=0.52 MW1−Pbase,20h=1−0.48=0.52 MWEnergy stored = 0.52×9.6=4.99 MWh0.52×9.6=4.99 MWh

• Discharging: in storage‑served hours (10.4h), discharge at Pbase,20h=0.48 MWPbase,20h=0.48 MWEnergy needed = 0.48×10.4=4.99 MWh0.48×10.4=4.99 MWh

So per MW of wind:

• BESS discharge power: PBESS,20h=0.48 MWPBESS,20h=0.48 MW

• BESS energy capacity:

  EBESS,20h≈4.99 MWh/MWwindEBESS,20h≈4.99 MWh/MWwind

• Duration:

  Duration20h=EBESS,20hPBESS,20h≈4.990.48≈10.4 hoursDuration20h=PBESS,20hEBESS,20h≈0.484.99≈10.4 hours

Comparison:

Target	BESS power per MW wind	BESS energy per MW wind	Effective duration
24/7 baseload (40% CF)	0.40 MW	5.76 MWh	14.4 h
20h/day supply (40% CF)	0.48 MW	4.99 MWh	10.4 h

So relaxing from 24h to 20h/day still leaves you needing a ~10‑hour battery at nearly 0.5 MW per MW of wind. That’s already “long‑duration” by UK BESS standards (most existing assets are 1–4h).​

4. Transmission-Scale BESS Costs in the UK (500 MW-class)

Bias the BESS capex towards transmission‑system‑scale assets (~500 MW) rather than small distribution projects.

Recent UK examples:​

1. CIP Scotland projects (Coalburn 1&2, Devilla):

   • Each project: 500 MW / 1,000 MWh (2‑hour duration), transmission‑connected.​

   • Project sponsors state these are “£400 million”‑class investments per 500 MW/1000 MWh unit.​

   • Implied costs:

     • £400m / 1,000 MWh = £400,000/MWh = £400/kWh

     • £400m / 500 MW = £0.8m/MW

2. Thorpe Marsh & West Burton C (Fidra Energy, National Wealth Fund):

   • Factsheet notes that the “current standard BESS asset in the UK is 100 MW and costs c. £600k per MW”, with Fidra targeting ~£465k per MW for large‑scale assets.​

   • For a typical 2‑hour 100 MW system, £600k/MW implies:

     • 100 MW costs £60m.

     • If 2h (200 MWh), that’s ~£300,000/MWh = £300/kWh.

3. Global/BNEF benchmarks (headline, not UK‑specific):

   • BloombergNEF’s 2024 survey shows global average turnkey 4‑hour BESS prices around US$165/kWh, with Europe notably more expensive.​

To bias high and focus on transmission‑connected 500 MW‑class systems, a conservative but defensible UK cost assumption today is:

• Central case:

  CBESS=£400,000/MWh=£400/kWhCBESS=£400,000/MWh=£400/kWh

  (aligned with the CIP 500 MW / 1 GWh examples).​

For sensitivity, we can note that at £300,000/MWh (more in line with Fidra’s implied standard asset), results would scale down linearly, but the central story remains the same.

5. Levelising BESS Costs at 10% Real WACC over 20 Years

10% real WACC and 20‑year life (aligned with CfD tenor) to convert capex into a per‑MWh adder:

• Capital recovery factor (CRF) for r=10%r=10%, n=20n=20:

  CRF=r1−(1+r)−n≈0.117CRF=1−(1+r)−nr≈0.117

So the annualised cost is approximately 11.7% of capex per year.

5.1 Storage Cost per MW of Offshore Wind

Using the 20‑hour case :

• Per MW of wind:

  • EBESS,20h≈4.99 MWhEBESS,20h≈4.99 MWh

  • Capex per MW wind:

    CapexBESS,20h=4.99 MWh×£400,000/MWh≈£1.996 millionCapexBESS,20h=4.99 MWh×£400,000/MWh≈£1.996 million

• Annualised cost per MW wind:

  ABESS,20h=1.996 m×0.117≈£0.234 m/yearABESS,20h=1.996 m×0.117≈£0.234 m/year

• Annual energy delivered by the firm block (20 hours/day):In the 20‑hour case, we deliver Pbase,20h=0.48 MWPbase,20h=0.48 MW for 20 hours/day:

  Eyear,load=0.48×20×365≈3,504 MWh/year per MWwindEyear,load=0.48×20×365≈3,504 MWh/year per MWwind

• Levelised incremental cost from BESS alone:

  ΔPCfD,20h=ABESS,20hEyear,load≈£234,0003,504 MWh≈£67/MWhΔPCfD,20h=Eyear,loadABESS,20h≈3,504 MWh£234,000≈£67/MWh

So, for 20h/day firm supply, under these assumptions the battery alone adds roughly:

• ~£65–70/MWh on top of the bare offshore wind CfD price.

For the 24/7 case:

• Capex per MW wind:EBESS,24h=5.76 MWh⇒5.76×£400k=£2.304mEBESS,24h=5.76 MWh⇒5.76×£400k=£2.304m

• Annualised:2.304×0.117≈£0.269m/year2.304×0.117≈£0.269m/year

• Delivered firm baseload power is 0.4 MW0.4 MW for 24h/day; annual energy is again 3,504 MWh/year (same total energy output, just spread over 24h rather than 20h).

• Incremental cost:

  ΔPCfD,24h≈£269,0003,504≈£77/MWhΔPCfD,24h≈3,504£269,000≈£77/MWh

Summary (given £400k/MWh, 10% WACC, 20‑year life):

Case	BESS energy per MW wind	Capex per MW wind	Annualised cost	Incremental storage cost (adder)
24/7 baseload	5.76 MWh	~£2.30m	~£269k/yr	~£75–80/MWh
20h/day firm	4.99 MWh	~£2.00m	~£234k/yr	~£65–70/MWh

If we instead used £300k/MWh as the unit cost, those adders would fall proportionally to roughly £50–55/MWh (20h) and £57–60/MWh (24/7).

6. Incremental CfD Price Required vs Today’s AR7 Prices

6.1 Base CfD prices (no storage)

From AR7 results:​

• Fixed‑bottom offshore wind CfD:

  • England & Wales: £91.20/MWh

  • Scotland: £89.49/MWh

  • Blended: £90.91/MWh

These prices buy intermittent energy only.

6.2 Offshore Wind + BESS for 20h/day Firm Supply

Add the incremental storage cost:

• Central case (20h/day, £400k/MWh, 10% WACC):

  • Offshore wind: ~£91/MWh

  • + BESS adder: ~£67/MWh

  • = ~£158/MWh all‑in firm(ish) price in 2024 terms.

For strict 24/7 baseload:

• Offshore wind: ~£91/MWh

• + BESS adder: ~£77/MWh

• = ~£168/MWh.

These figures ignore:

• Any system‑service revenues or arbitrage income for the battery (which could offset some cost).

• Any multi‑day or seasonal storage requirement (which would increase the effective cost of full firming).

• Network charges, connection costs, and ancillary system costs (again, likely upwards).

6.3 Comparison Against Other Technologies

DESNZ’s new cost figures, released alongside AR7, quote levelised costs (LCOE) of approximately:​

• New CCGT: ~£147/MWh

• New nuclear (large): ~£124/MWh

On a strictly firm‑power basis, this implies:

• Offshore wind (intermittent only):

  • Very competitive at ~£91/MWh, well below new gas and slightly below new nuclear.

• Offshore wind + long‑duration BESS to reach ~20h/day firmness:

  • ~£155–160/MWh central case.

• Offshore wind + BESS for true 24/7 baseload:

  • ~£170/MWh or higher.

In other words, once you pay to firm offshore wind using today’s UK transmission‑scale batteries at a 10% WACC, the all‑in cost rises to the point where it is more expensive than new nuclear per MWh of firm output, and materially above new gas.

7. Sensitivities and Practical Considerations

7.1 Higher Load Factors (e.g. CfD 49%)

If we repeat the storage sizing with c=49%c=49% (DESNZ CfD assumption for new offshore):​

• The energy budget per MW wind becomes 11.76 MWh/day.

• Under a similar binary model:

  • 24/7 case requires ~6.0 MWh of storage per MW wind and ~12.2h duration (vs. 5.76/14.4h at 40%).

• Because both the energy and power scale with CF, the net change in £/MWh adder is modest – the system still needs a large, multi‑hour battery.

So using the more optimistic 49% CF improves the economics slightly, but does not change the core conclusion: long‑duration BESS to turn offshore into firm power remains expensive.

7.2 Cost Declines and Lower WACC

• BNEF and others expect further sharp falls in BESS capex, with global turnkey prices already at ~US$165/kWh on average in 2024, and even US$85/kWh in China.​

• If UK transmission‑scale projects converged from £400/kWh to, say, £200/kWh, and WACC fell from 10% to 6% real, the storage adder could plausibly halve, moving into the £30–40/MWh range for 20h/day supply.

• Even then, the all‑in firmed price would likely still be >£120/MWh when added to offshore wind CfDs.

7.3 Beyond Intra-day Variability

The analysis above focuses on a stylised intra‑day pattern with binary generation and no multi‑day droughts. In practice:

• Wind droughts lasting several days in winter are well‑documented in GB wind statistics.​

• Covering those purely with Li‑ion BESS drives storage durations towards multi‑day or even multi‑week, which is economically prohibitive at any plausible BESS cost.

• System planners expect diversification (geographic spread, interconnection, demand flexibility, other low‑carbon firm sources such as nuclear or CCS) to deal with those events, not BESS alone.​

8. Implications for SMR’s Comparative Advantage in the UK

Putting this together:

1. AR7 confirms that intermittent offshore wind is cheap but not firm.

   • ~£91/MWh CfD for energy that does not run 24/7.​

2. Firming offshore with today’s transmission‑scale BESS is expensive at UK costs and 10% WACC.

   • To approach 20 hours/day of firm supply with a 40% CF wind fleet, you need ~10–11h of storage and an incremental £65–70/MWh adder at current UK 500 MW‑class BESS capex.​

3. All-in “firm offshore wind” costs are above new nuclear and gas on a pure LCOE basis.

   • Wind only: ~£91/MWh

   • Wind + BESS (20h/day): ~£155–160/MWh

   • Wind + BESS (24/7): ~£170/MWh

   • New nuclear: ~£124/MWh; new gas: ~£147/MWh.​

4. SMR/AMR offers structurally different value:

   • High capacity factor (typically modelled at >90%), inherently 24/7, dispatchable within ramp constraints.​

   • No requirement for massive multi‑hour batteries to convert intermittent output into firm supply.

   • When judged on “firm MWh delivered at the meter”, SMR/AMR economics look much more competitive relative to offshore+storage than if one compares offshore’s bare CfD strike to SMR’s LCOE.

5. For a data‑centre hub:

   • If the requirement is true 24/7 or near‑continuous supply, the system‑cost comparison is not:

     • “Offshore wind at £91/MWh vs SMR at £X/MWh”but rather:

     • “Offshore wind + firming (BESS, peakers, demand response, interconnectors) vs SMR PPA”.

The stylised numbers above show that, at current UK BESS costs and a 10% real WACC, the incremental CfD uplift required to make offshore wind behave like a quasi‑baseload resource is of the same order (or higher) than the entire offshore wind CfD strike itself.

That gap – between intermittent CfD prices and the true cost of firm low‑carbon supply – is precisely where SMRs can make a credible economic case, especially for industrial parks, ports and data‑centre campuses that value 24/7 availability more than marginal £/MWh on a purely intermittent basis.