Ørsted – another goner with the wind

A deep dive into Danish wind farm operator Ørsted

Danish wind farm operator, Ørsted – owner of the largest capacity of installed offshore wind power globally – has just completed its rights issue, raising DKK60bn ($9.3bn)¹ of new equity funding, almost equivalent to its previous market capitalisation. Two-thirds of the money raised has been earmarked as needed to finish the New York Sunrise offshore wind farm; a project that will create no economic value for Ørsted investors; and where its previous joint-venture partner effectively handed back the keys just over 12 months ago.

In our experience, there are three types of equity rights issues: good businesses needing to raise capital to accelerate growth; good companies needing to fix bad balance sheets; and bad companies, that will always have bad business models that want to extend (liquidity) and pretend (the model works). The first two examples can make good investments; the third will always be a disaster: investors are simply throwing good money after bad. We believe that Ørsted’s is an example of the third type of rights issue.

We also note that in spite of the significant fall in share price, Ørsted’s management have bought only a token number of shares during the rights issue process,² whilst the CEO has refused to rule out coming back to the market with an additional rights issue.³

Ørsted’s business model is now almost entirely focused on building offshore wind farms.⁴ These projects have always been reliant on generous subsidies to be economically viable. Yet as governments have tried to increase wind market share, subsidies have necessarily become less generous. At the same time, offshore wind projects have had to become more ambitious in scale. This means that Ørsted investors are taking more project risk and more financial risk in order to make diminishing returns. We argue that unsubsidised offshore wind will never be economically viable, whilst subsidised offshore wind will never be economically scalable. This means Ørsted’s business model increasingly offers investors that most unpalatable cocktail of return-free risk.

As well as being dependent on generous regulatory subsidy (which is unsustainable at scale since it increases the cost of electricity for consumers leading to demand destruction), Ørsted’s capital-intensive developer business model necessitates asset turn via sales (“farm downs”) of passive stakes in projects to third party investors. As profitability of projects has declined (and interest rates have risen), the valuation multiples achieved by Ørsted have steadily deteriorated, placing more strain on its own balance sheet, resulting in more dilution for its shareholders.

Ørsted’s other source of cash-flow is dividends from its wind farm projects. Older projects under more generous regulatory regimes have generally been more profitable and able to upstream dividends. Yet these projects are too small to fund Ørsted’s growth and are themselves subject to rising operating cost (Opex/MW) trends as ageing wind turbines need to be repaired; and will eventually be subject to decommissioning costs when their regulatory subsidy ends. Ørsted recognises these decommissioning costs on its balance sheet as a future liability yet is not building any ringfenced cash to fund them. These decommissioning costs in addition to financial debt held within individual wind projects, represent hidden financial leverage for investors at Ørsted group level.

We believe Ørsted’s financial reporting does not give investors sufficient information to assess the efficacy of its business model.

Ørsted’s ability to generate value for its shareholders is highly dependent on it deploying capital efficiently, yet in its recently issued rights issue prospectus, it claimed that “given the Group’s capital-intensive portfolio of assets, the Group’s primary operations are best measured by excluding depreciation and financing cost.”⁵ Ørsted group accounts therefore focus on accounting profitability measures like EBITDA (Earnings Before Interest Tax Depreciation and Amortisation) and FFO (Funds from Operations) which exclude depreciation and amortisation, essentially assuming that capital in its business model does not have a cost or seek a return. Perhaps these are the type of investors for whom Ørsted offers some appeal.

Through focusing on proportionately consolidated group EBITDA targets, that make no charge for capital or debt servicing at either the wind farm or group level, it is possible for the Ørsted group accounts to suggest profitable growth without any of the underlying assets able to earn a return on that capital, generate free cashflow or pay dividends. As Warren Buffett famously warned in the 2000 Berkshire Hathaway Annual Report:

“References to EBITDA make us shudder – does management think the tooth fairy pays for capital expenditures?”⁶

There is a long list of companies that have gone bust despite reporting healthy (or even record) EBITDA: Enron (2001), Worldcom (2002), Global Crossing (2002), NTL (2002), Charter Communications (2009), Intelsat (2020), and WeWork (2023); either by capitalising operating expenses (Opex) as capital expenditure (Capex), or more commonly, over-investment in assets that turned out not to generate sufficiently profitable cash-flow (which we believe is the case with Ørsted).

If the accounting stinks, then the disclosure sucks.

If, as Ørsted seems to believe, the immaturity of its asset base makes the underlying profitability of these assets difficult to measure at group level, then it seems logical that it might instead want to be more transparent about the economics of mature individual wind farms currently in operation.

Instead, any investor reading Ørsted’s annual report will find we get almost zero disclosure (in 258 pages) about the 32 individual offshore wind farm assets it owns and operates and is currently continuing to develop. Instead of allowing investors insight into the economics of individual wind farms, we get an amazing 114 pages of ESG guff – even an unnecessary and self-indulgent insight into the favoured pronouns of its Board Members.⁷

We suggest that behind this cloak of morality and absence of transparency is a rent-seeking business model that rips off both consumers and investors: a woke money-pit.

Given the absence of adequate disclosure from Ørsted at group level, our research has focused on the economics of individual offshore wind projects, using other sources of publicly available information, particularly the statutory annual accounts of its UK offshore wind farms that have been filed at Companies House as well as other regulatory filings. Our work is, however, limited by the public accounts available (particularly outside the UK), and lack of detailed company guidance on the economics of projects in development. We also note that many of the UK projects are yet to submit 2024 accounts.

Are Ørsted’s Sunrise and Revolution offshore wind projects a “green scam”?

On September 23rd, 2025, President Trump addressed the United Nations General Assembly, where he warned delegates that “wind power doesn’t work – it’s unreliable, it’s expensive, it’s just not going to power our future.”⁸

The previous day, Ørsted won a preliminary injunction against the Federal Bureau of Ocean Management’s (BOEM) “Stop Work Order”, allowing them to continue work on their (50% owned) 704 MW Rhode Island Revolution offshore wind project,⁹ and avoiding what Ørsted claims would be significant cost escalation post September owing to scheduling of installation boats. Revolution – like all US offshore wind projects – is being constructed on federal seabed, hence President Trump’s authority in attempting to stymie its progress.¹⁰

We understand Ørsted could still receive a similar Federal veto on its bigger (100% owned) Sunrise offshore wind project, which unlike Revolution could not be argued as being near completion, reducing the chances of a successful legal challenge to any future federal “stop work” order.¹¹ There is also some uncertainty about whether the Court which granted the relief on Revolution had the necessary authority.¹²

Nevertheless, ignoring this ongoing risk, we thought it would be interesting to assume both Sunrise and Revolution Wind are completed on schedule and to examine the economics of Ørsted’s two most significant American offshore wind projects to assess whether they support President Trump’s argument that wind, and particularly offshore wind, is part of a “green scam.”¹³

Sunrise Wind

Ørsted says that two-thirds of the $9.3bn newly raised ($6.25bn) is ear-marked for further investment in the (924 MW) Sunrise offshore wind project, off Long Island, New York, owing to a funding gap that has arisen since they were unable to flip the 50% stake they previously bought from US utility Eversource for just $152m in July 2024,¹⁴ and that this resulted in “an incremental funding requirement of around DKK40bn ($6.25bn) from a lack of proceeds, non-recourse project financing and higher CAPEX contribution following full ownership.”¹⁵

Because of the recent rights issue being detailed to fix Sunrise Wind, Ørsted has necessarily been forced to disclose more information than normal on its US assets, enabling us to assess their future profitability more easily than other Ørsted offshore wind farms currently under construction on which the company has given no formal profitability guidance.

Sunrise, which is now 35% complete, is currently valued in Ørsted’s balance sheet at $1.37bn (after $1.4bn of net impairments).¹⁶ Another $6.25bn of capital expenditure (plus $343m¹⁷ of additional costs) means that the total capital invested in Sunrise will be at least $9.76bn.¹⁸ Upon completion of the project, Ørsted will receive a 30% net tax credit rebate on its investment of $2.8bn. We also understand that the future capital expenditure is already committed and therefore is being treated by Ørsted as largely a sunk cost.¹⁹ Hence, why the company is so determined to finish the project, seemingly throwing good money after bad.

This tax credit is not the only or even the biggest subsidy. The project will also receive a guaranteed price of $146/MWh,²⁰ (up from the original award of $110/MWh) for its power generation over 25 years, which is over six times higher than the average electricity price in New York in 2024 of just $23/MWh²¹ (despite intermittent power having a very low value (zero at high market share) to the grid compared to baseload (always on) or dispatchable (can be switched on and off) power generation.)²² We estimate this subsidy is worth $448m²³ per year over 25 years. Over the life of the project, this means another $11.2bn of subsidies (NPV of $4.8bn), or a total of $14.1bn, compared with $9.76bn invested by Ørsted. (See Fig. 1: Sunrise investment vs subsidies).

Fig.1 | Sunrise investment vs subsidies

But if you think that Ørsted gets a dollar and a half of subsidy for every dollar of investment it makes on Sunrise, and that this will make it a lucrative investment for Ørsted investors, then you would be wide of the mark.

Ørsted recently disclosed that once operational, Sunrise will generate run-rate EBITDA of DKK3.5bn ($550m). Excluding the (P&L accounting for the) tax rebate, this means the run-rate EBITDA guidance is DKK2.8bn ($436m). For Ørsted shareholders (and applying a reducing balance over the life of the asset depreciation charge to the EBITDA guidance),²⁴ we calculate that Return on Capital Employed (ROCE) which includes a charge for capital (EBIT/Capital Employed) is negative for the first ten years of the project. (See Fig. 2: Sunrise Run Rate Profitability EBITDA vs EBIT). In fact, based on our EBIT figures, the net present value (NPV) of EBIT over the life of the asset is minus $500m.²⁵ However, on a cash-flow basis, the guidance given implies that Sunrise will generate an annual return on investment (EBITDA/Invested Capital) of just 6.3% (4.5% ex tax credit) but including all subsidies the annual (EBITDA/Invested Capital) for the project as a whole (and therefore the US economy) falls to just 0.1%!²⁶

Fig.2 | Sunrise Run Rate Profitability EBITDA vs EBIT ($m)

Sunrise Wind will therefore rip off the New York electricity consumer, whilst also failing to provide an adequate return for investors. This appears to be a scam that will make no one rich.

Revolution Wind

We calculate that Revolution Wind has even worse economics, due to less egregious revenue subsidies.

Upon completion of the DKK40bn ($6.32bn) project, Ørsted will receive a tax credit subsidy of DKK6bn ($942m) for 30% of their share (DKK20bn or $3.16bn) of investment. The project also has an additional subsidy: a 20-year Power Purchase agreement (PPA) with Rhode Island and Connecticut at $100/MWh. ²⁷ This compares to an average electricity price in these states last year of $27/MWh.²⁸ We estimate this annual subsidy to be worth $4bn over 20 years ($2bn to Ørsted) or $204m annually to Revolution ($102m to Ørsted). Over the lifetime of the project, this means a total of $2.9bn of subsidies, compared to $3.4bn invested by Ørsted. (See Fig. 3: Revolution investment vs subsidies).

Fig.3 | Revolution investment vs subsidies

Ørsted has suggested that their stake (50%) in the project will generate DKK1bn ($157m) EBITDA annually (excluding the tax rebate we calculate DKK700m ($110m)). We also estimate (after applying depreciation to the EBITDA guidance) that Return on Capital Employed (ROCE) (which includes a charge for capital (EBIT/Capital Employed)) is negative for the first fourteen years of the project. (See Fig. 4: Revolution Run Rate Profitability EBITDA vs EBIT). In fact, based on our EBIT figures, the NPV of EBIT over the life of the asset is minus $800m.²⁹ However, on a cash-flow basis the profitability guidance implies that Revolution will generate an annual cash return on its investment (EBITDA/Invested Capital) of just 4.5% (3.3% ex tax credit) but including all subsidies the annual cash return (EBITDA/Invested Capital) for the project (and the US economy) falls to minus 0.2%! ³⁰ This is the type of capital allocation that communist economies do at scale before they fail.

Fig.4 | Revolution Run Rate Profitability EBITDA vs EBIT ($m)

Given Ørsted’s chequered history in its inability to manage wind project costs in America, since 2023 writing off $6.2bn of previous investments that turned sour ($3.2bn relating to the now defunct Ocean Wind project in 2023), it is tempting to believe that Ørsted’s American problems are idiosyncratic and that economics for its investors in the rest of the world, and particularly the UK, where it has most exposure, are superior.

This argument might be supported by headline build costs for Sunrise we calculate as $10.2bn/GW and for Revolution of $8.9bn/GW³¹ against UK North Sea costs which we estimate to be currently running at $4.85bn/GW,³² (including building the transmission (OFTO) asset, which Ørsted excludes from Capex and is instead funded from working capital). The UK headline figure is therefore roughly half the headline US number. Ørsted says its US construction costs have been inflated by idiosyncratic factors such as absence of local supply chain including boats or recent higher costs owing to tariffs or federal intervention. However, we believe that when the 30% tax credit in the US is taken into account (not available in the UK) that net construction costs in the US and the UK are more similar (Sunrise net costs are reduced to $7.14bn/GW and Revolution to $6.24bn/GW))³³ than is commonly appreciated. (See Fig. 5: North Sea construction costs vs. Revolution Wind and Sunrise Wind).

Fig.5 | North Sea construction costs vs. Revolution Wind and Sunrise Wind ($m)³⁴

As we will demonstrate, where this argument that UK assets are more profitable has some merit is related to the legacy portfolio of Ørsted UK wind farms that receive egregiously high subsidies from the ROC and early CfD subsidy schemes. However, we argue that such generous project economics are not scalable in the UK.

Since 2017 there has been a significant reduction in UK headline CfD subsidies meaning that recently completed projects and particularly the giant Hornsea 3 offshore wind farm currently under construction (10% complete) will have significantly inferior economics, more comparable we think to Sunrise and Revolution.

The UK: without subsidies unviable; with subsidies unscalable

The UK is Ørsted’s biggest market (See Fig. 6: Ørsted Offshore Wind Country Exposure), with 5.7GW of installed capacity (out of a total of 15.9 GW in the UK)³⁵ and a further 3.3GW under construction (out of a total of 10.4GW in the UK.)³⁶ The current UK government has a somewhat unrealistic target of 43-50GW by 2030. ³⁷

Fig. 6 | Ørsted Offshore Wind Country Exposure ³⁸

Ørsted currently has twelve operational UK wind projects (See Fig. 7: Ørsted UK installed capacity (MW) by year of commercial operation date),³⁹ which we have modelled,⁴⁰ dating back to comparatively small but extraordinarily generously subsidised, Barrow (90MW) and Burbo Bank (90MW) which became operational (commercial operation date (COD)) in 2006 and 2007 respectively. They will also be the first Ørsted UK projects to lose their (ROC) subsidies in 2027.

Fig. 7 | Ørsted UK installed capacity (MW) by year of commercial operation date

Not viable without subsidies

It is no coincidence that Ørsted chose to concentrate development in the UK, given that successive governments have offered the most generous subsidy regimes (See Appendix 1: Snouts in the Trough, a brief history of the UK subsidy regime). Ørsted recently disclosed that between 2025-30 it expects 85% of revenues to be derived from fixed price subsidy schemes.⁴¹

Ørsted discloses these subsidies (annual CfD payments above the Market Reference Price (market price) in the accounts of its UK individual wind farms. Between 2018-23, we calculate Ørsted’s UK wind farms received a cumulative £6.7bn (Ørsted’s share £3.4bn), funded by increases in UK electricity bills.

Fig. 8 | Ørsted UK wind farm subsidies

Without subsidies, we calculate that nine out of 12 projects have generated a cumulative operating loss and only three Ørsted projects would have generated a marginal cumulative operating (EBIT) profit (Burbo,⁴² Hornsea 1, Hornsea 2), the latter because it benefitted from the abnormally high electricity prices (2022), which have since declined, when it commenced generation, choosing to delay switching on its CfD (See Fig. 9: Ørsted UK wind farm cumulative profit vs cumulative subsidies).

Fig. 9 | Ørsted UK wind farm cumulative profit vs cumulative subsidies

It is also worth noting that even in 2022, in a year of abnormally high gas and electricity prices, according to their published and audited accounts, every Ørsted UK wind farm apart from Hornsea 1 was a net receiver of (ROC, CfD or REGO)⁴³ subsidy, busting the myth that UK electricity consumers somehow have ever benefitted from a “reverse subsidy”.⁴⁴ (See Fig. 10: Ørsted share of subsidies by project).

Fig. 10 | Ørsted share of subsidies by project ⁴⁵

The recent CfD wind farms are less profitable than the recent ROC farms, which we believe is due to the CfD scheme (introduced after 2014 for offshore wind farms that came into operation after 2017)⁴⁶ being (increasingly) less generous than the old ROC scheme (See Appendix 1: Snouts in the Trough: a brief history of the UK subsidy regime).

To highlight this point, we have also calculated the average return on capital employed by site since its commercial operation date. (See Fig. 11: Average return on capital employed by commercial operation date). We believe this highlights that CfD projects are increasingly less economically viable, whilst although ROC projects are generally more profitable, there is also some variability (which we will attempt to explain).

Fig. 11 | Average return on capital employed by commercial operation date

Rising operational costs: do wind turbines really last 30 years?⁴⁷

When we examine the variations of profitability of the ROC farms further we find that with the exception of Burbo (2007), which we believe benefits from cross subsidisation from Burbo Extension, the older ROC wind farms are less profitable than more recent farms (See Fig. 12: Last disclosed operating profit margin by commercial operation date).

Fig. 12 | Last disclosed operating profit margin by commercial operation date

Although the wind industry maintains that wind turbines last up to 30 years (and depreciates them accordingly)⁴⁸ we are more sceptical, noting not only rising recent warranty costs at wind turbine OEMs,⁴⁹ but also in our analysis of operating trends at Ørsted UK offshore wind farms a declining capacity utilisation over time, (See Fig. 13: Load factor of ROC farms by year of operation).

Fig. 13 | Load factor of ROC funded farms by year of operation (%)⁵⁰

The offshore wind industry likes to blame declining capacity utilisation in general on less windy weather each year,⁵¹ but we think a more credible explanation is that as they age, wind turbines need more maintenance capital expenditure or need to be replaced. Given they are exposed to worse conditions, this is a particularly acute problem for offshore turbines.

This problem impacts profitability since older wind farms will need to spend more money repairing or replacing turbines, hence we observe rising OPEX/MW trends at wind farms that have been operational for more than a decade. (See Fig. 14: Direct costs of older ROC units by year of operation (£/MWh).

Fig. 14 | Direct costs of older ROC units by year of operation (£/MWh)

We see a similar trend at Horns Rev 2 wind farm (a wind farm located in Denmark), which when it commenced operations in 2009, was the world’s largest offshore wind farm. According to its disclosed accounts, its load factor has decreased from over 50% to less than 45%. Direct costs per MWh have also been steadily rising and now stand at near DKK 240/MWh. (See Fig. 15: Load factor (%) and direct cost per MWh for Horns Rev 2 wind farm).

Fig. 15 | Load factor (%) and direct cost per MWh for Horns Rev 2 wind farm

The sweet spot for Ørsted’s UK ROC wind farms profitability are the last ROC wind farms that came into operation between 2014 and 2018 (West of Dutton Sands, Westernmost Rough and Race Bank) (See Fig. 12: Last disclosed operating profit margin by commercial operation date). We note that despite its very generous ROC subsidy, Barrow (2006) is now only marginally profitable, perhaps because of rising costs of operating, and falling capacity utilisation, probably linked to wear and tear on turbines. With the notable exceptions of Walney 1&2 (2011) and Lincs (2013) (See Fig. 14: Direct costs of older ROC units by year of operation (£/MWh) and Fig. 16: Direct costs of younger ROC units by year of operation (£/MWh), both of which have high Opex/MW costs, the farms on the old ROC subsidy scheme generate a far higher return on capital employed than those on the new CfD scheme (See Fig. 11: Average return on capital employed by commercial operation date).

Fig. 16 | Direct costs of younger ROC units by year of operation (£/MWh)

Decommissioning Liabilities: who will pay?

We are intrigued as to when the subsidy regime runs-out (as it is slated to do for both Burbo and Barrow in 2027) whether these assets – which as we have noted are facing rising Opex/MW trends - will still generate cash or more likely be abandoned by their owners, requiring them to be decommissioned. (See Fig. 17: UK Wind Farms and Subsidy Expiry Date).

Fig. 17 | UK Wind Farms and Subsidy Expiry Date

Decommissioning costs are shown in project accounts as liabilities (See Fig. 18: Gross decommissioning provision - £m). The rights issue prospectus notes that by the end of June 2025,⁵² provisions for decommissioning were DKK13.7bn (£1.6bn) but that “such estimates may be incorrect or underestimate the actual decommissioning costs.” These decommissioning provisions which will become cash costs at the end of the life of the asset are typically being discounted back at 4.25%, so that when they become cash costs the future realised figure will be more like £3.5bn. We find £788m of decommissioning provisions in the accounts of the UK wind farms. However, crucially neither in the wind project accounts or the group accounts do we see cash being accrued to offset the decommissioning provision. We also note that if any of the wind farms get decommissioned earlier than expected, the cash cost to Ørsted shareholders will rise significantly.

Fig. 18 | Gross decommissioning provision (£m)

We also note that Reform UK – currently on course to be in government by the time (2029) any offshore wind projects awarded in AR7 are built – have warned developers that if elected it will seek to cancel contractual terms.⁵³ Meanwhile, the Conservative Party, who will perhaps form a post-election coalition government with or have their proposals copied by Reform, have now advocated abolishing ROC subsidies entirely⁵⁴ and abolishing carbon taxes on power generation.⁵⁵ We believe that this would crystalise a profitability and decommissioning crisis at Ørsted’s oldest and most profitable UK offshore wind farms.

We calculate that without ROC subsidies, Ørsted’s UK offshore wind ROC portfolio (which includes eight wind farms) would have made a cumulative EBITDA loss. We therefore believe that if this policy were implemented it would result in a hit to Ørsted at the group level of c. £458m EBITDA (c.10% of group)⁵⁶ but it would also mean Ørsted (or its subsidiaries) would be responsible for decommissioning costs (which they have not put any cash aside for) and which we calculate to be c.£90m by 2029 and c.£219m if forced to decommission the assets in 2031. If Ørsted decided that the decommissioning liability was non-recourse, then Ørsted could walk away and leave the UK government on the hook for decommissioning costs (prompting awkward questions of why this issue has not previously been addressed by the UK government).

Fig. 19 | Ørsted ROC UK Wind Farms and Subsidy Expiry Date

Fig. 20 | Illustrative EBITDA impact from carbon cost & subsidy removal and decommissioning

Hornsea: Bigger, less profitable projects = more risk

We argue that unsubsidised offshore wind will never be economically viable, whilst subsidised offshore wind will never be economically scalable. As various UK governments have set more challenging (and in our view economically suicidal)⁵⁷ targets for offshore wind market share, Ørsted’s UK offshore wind projects have had to become more ambitious in scale, focusing on the Hornsea projects (See Fig. 21: Ørsted UK Installed capacity (MW) by year of commercial operation date).

Fig. 21 | Ørsted UK Installed capacity (MW) by year of commercial operation date

The installed capacity within the UK has ramped up in recent years with 1.2 GW (over 152 sq. miles) Hornsea 1 in 2019⁵⁸ and 1.32 GW (over 178 sq. miles) Hornsea 2 in 2022.⁵⁹ Hornsea 3, which at 2.9GW (over 269 sq. miles) will be the biggest offshore wind farm ever built, is scheduled to begin operation in 2027.⁶⁰ Ørsted was also awarded Hornsea 4 (2.4GW) in AR6 (September 2024), coincidently while Hornsea 3 was allowed to rebid capacity,⁶¹ but in May 2025 discontinued the project on economic viability grounds,⁶² despite the CfD subsidy at £84.97/MWh (2025 prices) being significantly more generous than Hornsea 3. Nevertheless, these three Hornsea projects (1-3) represent 5.4 GW (out of 9GW, or 60%) of Ørsted UK offshore wind exposure (installed and under construction).

We have modelled the profitability of Hornsea 1, 2 and made an estimate for Hornsea 3, based on similar assumptions with the key differences of the lower CfD subsidy and higher build costs (though we also think there could be issues with inferior seabed sites and “wind wake”).⁶³ It should be noted that the existing Hornsea projects (1&2) have opaque holding company structures,⁶⁴ so we have built pro-forma models to estimate their project profitability.

Hornsea 3: what are the capital costs?

The total estimated cost of building Hornsea 3 has been variously estimated in the press to be £10-11bn⁶⁵ or £8.5bn.⁶⁶ Ørsted has subsequently clarified that up to one third of UK offshore wind project investment is typically for “transmission assets” which are developed by Ørsted under “working capital” and “inventory”⁶⁷ (still needing to be funded by Ørsted) but are subsequently sold off as a regulatory asset to a third party investor.⁶⁸ We have assumed that the Capex for Hornsea 3 power generation assets is £8bn, with transmission assets of £2.5bn (are funded out of working capital), a similar multiple of capital costs to the transmission assets of Hornsea 2.

Ørsted’s rights issue presentation⁶⁹ specifies a future commitment to Hornsea 3 (which is only 10% complete) as DKK25bn (£3bn), but with the caveat that this only relates to its share (the assumption being 50% after a farm down) of the power generation assets. Therefore £8bn for Hornsea 3 seems a reasonable overall Capex estimate for only the power generation assets.

We note that this cost per generation asset is £2.76bn per GW ($3.72bn) compared with Hornsea 2 which was built for £2.4bn (for 1.36GW or £1.76bn/GW) (a 55% cost increase) and adding back the transmission asset £3.68bn/GW (compared to Sunrise of £6.6bn/GW gross and £4.6bn net of tax credit).

How profitable can Hornsea 3 be with a £60/MWh CfD?

The Hornsea 3 CfD subsidy (£59.78 in 2024 prices) is well below the subsidies for Hornsea 1 (£200 MWh in 2024 prices) and Hornsea 2 (£80.1 in 2024 prices). We therefore believe it is necessary to ascertain just how profitable Hornsea 3 will be.

Our modelling suggests that whereas Hornsea 1 is significantly more profitable than Hornsea 2, deriving in 2023 £471m of revenue (53%) from subsidy, generating an 82% EBITDA margin and a 39% EBIT margin; Hornsea 2, derived in 2023 negligible revenue from subsidies, since it decided to switch its CfD on late, thus benefitting from the brief period of more elevated power prices, which have since normalised; generating a 69% EBITDA margin and a 26% EBIT margin. Modelling Hornsea 3 as receiving no revenues from subsidies in a period of more normal power prices but with higher Capex and depreciation costs, we estimate 50% EBITDA margin (c. £300m) but negative EBIT until 2035. This would constitute a cash return on invested capital (EBITDA/Capital Invested) of just 3.7%.⁷⁰ (See Fig. 22: Estimated Profitability of Hornsea projects).

Fig. 22 | Estimated Profitability and EBITDA/Capital Employed of Hornsea projects⁷¹

Based on our analysis, Hornsea 3 will not generate an EBIT profit until Year 11 of the project. (See Fig. 23: Hornsea 3 EBIT).

Fig. 23 | Hornsea 3 EBIT (£m)

Farm downs: a bear market

Ørsted’s capital-intensive developer business model necessitates asset turn via sales (or “farm downs”) of passive stakes in projects to third party investors. As profitability of projects has declined (and interest rates have risen), the valuation multiples achieved by Ørsted have steadily deteriorated, placing more strain on its own balance sheet and leaving its own investors to hold the bag. (See Fig. 24: Farm down multiples in year of COD – EV/MW).

Fig. 24 | Farm down multiples in year of COD – EV/MW (£bn/GW)

We previously disclosed the current build costs in the North Sea, Revolution Wind and Sunrise Wind. (See Fig. 5: North Sea construction costs vs. Revolution Wind and Sunrise Wind). We note that headline build costs at Sunrise and Revolution were £7.66bn/GW and £6.7bn/GW, whilst we believe they will be £2.81bn/GW for the generation assets of Hornsea 3 (£3.65bn/GW including transmission assets). Therefore, disposal proceeds would appear to now be at or below gross build costs, which is an alarming and unsustainable development.

We have calculated valuation multiples (EV - £bn/GW) based on the commercial operation date. We have extended the work to not only include just UK assets but assets in Taiwan (Greater Changhua 1 & 4) and the US (Ørsted farm down in South Fork Wind and Eversource’s farm downs of South Fork, Revolution Wind and Sunrise Wind).

Older vintages of wind farms have achieved higher valuation multiples, with 2019 being the peak vintage. Recent weaker multiples include Ørsted’s farm down of South Fork and Revolution Wind and Eversource’s farm down of Sunrise Wind to Ørsted. ⁷²

Ørsted has described the market as a “buyers’ market” with both valuations and volume of transactions markedly declining. If Ørsted is unable to “farm down” equity stakes to third party investors in its projects, it will have insufficient cash-flow to fund not only future projects but also service its group debt. Although it generally discloses valuation multiples for “farm downs”, Ørsted’s recent prospectus admits that “Ørsted has indemnities and liabilities post sale which are generally not disclosed.”⁷³ This reads to us like Ørsted sweetens the deal for third party investors to inflate valuation multiples that investors might apply to its residual stake (that doesn’t rank pari passu in its value or seniority).

In view of the probable low profitability and high capital intensity of Hornsea 3, and the fact that 50% (£4bn) of the power generation Capex (and all of the estimated £2.5bn of transmission “working capital”) is unfunded in Ørsted’s business plan, the successful “farm down” of Hornsea 3 is crucial, in our view, to the viability of the company.

The story that Ørsted is in advanced pre-contractual negotiations with a preferred bidder regarding the divestment of a 50% ownership interest in Hornsea 3 has appeared many times in the financial and industry press over the past few months.⁷⁴

The question of Ørsted’s “farm down” of Hornsea 3 is addressed in the recent rights issue prospectus, informing us that the divestment is being assessed from a “value creation, risk diversification and capital management” ⁷⁵ criteria, with a particular emphasis on the latter. Our interpretation of this is that Ørsted are warning that they are unlikely to create any value because they need to prioritise the funding. It goes on to say that “it is noted that from an accounting perspective, it is expected to recognise an upfront, non-cash EBITDA loss” for 2025 “of DKK3.5-5bn” (£413m-590m), which is currently excluded from its market guidance on annual profitability.

This reads to us like a sweetener in terms of initial EBITDA split to the third-party investor, which may flatter the disposal multiple, but will put extra strain on the cash-flow and balance sheet of Ørsted (since Ørsted will receive less EBITDA or dividends in the early years of the project than its “farm down” partner). This is one of many significant risks to Ørsted’s business plan.

Balance sheet: what is net debt?

We believe there are two key issues related to Ørsted’s balance sheet which need to be addressed: namely, what is the true level of group indebtedness; and in so far as they can be ascertained, what are the off-balance sheet liabilities.

At the end of June 2025, Ørsted had gross debt of DKK103bn (£12bn) of which DKK84bn (£9.7bn) is bank and bond debt and gross cash of only DKK12bn (£1.4bn). Yet the company claims – largely by treating hybrid debt preference shares which pay generous guaranteed dividends as 50% equity – that its “interest bearing net debt” is only DKK67bn (£7.8bn) rather than DKK91bn (£10.6bn). No wonder the newish Finance Director was unsure when on the Q2 conference call, he was asked to clarify the exact net debt figure.

As for off balance sheet liabilities, we have already discussed and quantified the unfunded decommissioning provisions (of up to £3.5bn) and seen how they could be triggered earlier than expected. We have also discussed the undisclosed contingent liabilities attached to “farm down” equity. This leaves the leverage positions of individual wind farms and the leverage used by buyers of “farm down” equity to juice their returns, which nonetheless represents “hidden leverage” in Ørsted’s asset base.

Based on accounts filed at the end of December 2024, we calculate the financial debt of individual UK wind farms of £7bn. (See Fig. 25: Progression UK offshore wind project debt), of which the main contributors are large projects that have commenced operations since 2018: Hornsea 1 £2.9bn, Hornsea 2 £2.1bn, Race Bank £830m and Walney Extension £1.1bn.

We understand that Ørsted’s proportionate share of this gross UK financial debt of c.£7bn, is roughly half, c.£3.5bn and although Ørsted classifies this debt as intra-company, it does not appear on the group balance sheet either as an asset or a liability. Ørsted will argue that this debt is “non-recourse” but since the first charge on the cash-flow from the specific wind projects is to service and eventually pay off this gross financial debt, it is Ørsted’s group debtholders who are subordinate and its group equity a leveraged play on leveraged (and marginally profitable only with time limited subsidies) assets.

Fig. 25 | Progression UK offshore wind project debt (£m) ⁷⁶

The rest of the debt, we calculate as £3.4bn, is an asset lent by third party farm down investors, but financed in holding companies within the third-party investors accounts. These third-party investor vehicles used to finance equity stakes in these four sizeable Ørsted projects have their own debt, which as per the annual audited accounts, stood at c.£6.5bn in 2024. (See Fig. 26: Third party investor debt vs amounts owed to third party investors from the individual wind farms). We estimate that equity “farm down” investment in Hornsea 1 was c.79% funded by debt, Hornsea 2 c.81%, Race Bank c.65% and Walney Extension c.68%.

We also calculate other assets including Taiwan to have c.DKK20bn of debt (c.£2.4bn). ⁷⁷ So there is gross UK offshore wind farm project debt of c.£7bn (Ørsted’s share c.£3.5bn) whilst the “farm downs” of the big four UK wind projects of £11.1bn have been funded with £8.3bn of external debt. ⁷⁸ This project debt compares to DKK103bn (£12bn) of gross debt and DKK91bn (£10.6bn) net debt disclosed on the Ørsted balance sheet.

Fig. 26 | Third party investor debt vs amounts owed to third party investors from the individual wind farms (£bn)

Funding: champagne tastes on a beer budget

Ørsted’s Capex commitments are staggering. It has committed investments of DKK145bn (£17bn) over three years (2025-27) and in 2025 alone of DKK50-54bn (£6bn) (of which DKKK25bn (£3bn) has already been spent), plus DKK15bn (£2bn) of committed hybrid coupons.

Fig. 27 | Gross investments through 2027 (£m) ⁷⁹

We note that the (£7bn) equity rights issue proceeds cover just over a year of capital expenditure. And as we have noted a further DKK38bn (£4.4bn) of Hornsea 3 is in our opinion unfunded by a business plan which seems aggressive in many of its assumptions. When we assess Ørsted’s stated funding plans (See Fig. 28: Funding 2025 – 2027) there are multiple areas of execution risk that mean Ørsted could easily breach this plan.

Fig. 28 | Funding 2025 - 2027 (as per Ørsted Sept 2025 business plan)

What is Ørsted group cash-flow?

If, as we previously noted, the Ørsted Finance Director struggled to pin-point a figure for group net debt, then ascertaining the underlying level of cash-generation at the parent company level is an even more imprecise exercise, since somewhat unusually Ørsted (and presumably its auditors) do not think it worth disclosing a parent statement of cash flows in the accounts:

Fig. 29 | Extract from 2024 group annual report regarding parent statement of cash flows

We are provided with a “consolidated statement of cash flows” which is instead the parent company share of proportionately consolidated EBITDA, adjusted for working capital. We have previously discussed the problems of using “EBITDA” as a measure of profit. This is not a cashflow statement that reflects free cashflow from assets, or specifically cash that can be “upstreamed” from Ørsted assets to the parent company.

In its business plan, Ørsted gives guidance for “cashflow from operations” over 2025-27 of a cumulative DKK50bn (£5.8bn), equating to an average of DKK17bn (c. £2bn per annum). Over the last ten years, only twice has this been greater than DKK17bn (£2bn), with large fluctuations (normally increases) in working capital. (See Fig. 30: Ørsted group cashflow from operations vs EBITDA). We understand that there will be a c. £2.5bn drawdown on working capital through funding of the Hornsea 3 transmission asset, but this might be offset by the tax credit from Sunrise and Revolution of £2.8bn. Nevertheless, as we have already noted, this is not a particularly useful financial metric for investors to assess cash generation at group level.

Fig. 30 | Ørsted group cashflow from operations vs EBITDA (£m) ⁸⁰

Aside from Danish biofuel generation assets, and European onshore wind assets, which we understand represent just 5% and 10% of group EBITDA respectively (with the onshore assets being up for sale and disposal proceeds already included in the business plan), Ørsted’s main source of regular cash-flow is its share of dividends from its operational UK offshore wind projects.

We have analysed Ørsted’s share of dividends from these projects (See Fig. 31: Dividends by individual wind project). As we can see from the progression of UK dividends, payouts are generally inconsistent, with only six of the twelve projects paying a dividend in 2023, whilst two-thirds of the dividends came from just two projects (Hornsea 1 and Race Bank). Ørsted share of UK offshore wind project dividends contributed £800m in 2022, falling to £700m in 2023. As the size of the new projects meaningfully increases, the dividend base from the legacy portfolio is too small to fund Ørsted’s growth.

Fig. 31 | Dividends by individual wind project (£m)⁸¹

If we are assessing cashflow “upstreamed” to the Ørsted parent company, we must consider the much lower annual level of dividends (£700-800m) relative to the “cashflow from operations” target of c. £2bn. In our communications with Ørsted, the company has claimed that “it is not possible to understand the profitability of each asset for the Ørsted group by looking at the local financial statements in isolation,”⁸² since there are holding company structures (which we think we have adjusted for) and “operations and maintenance service” contracts (which are not publicly disclosed).

We do not believe that investors should give Ørsted the benefit of the doubt for undisclosed profitability or cashflow which cannot be accounted for. We also think it unlikely that Ørsted’s share of profits is materially superior to its third party investors (in fact suspect the opposite given the need to recycle capital through “farm downs”). We would point out that the onus is on Ørsted to disclose profitability of operational assets and ability to “upstream” cash-flow. We note it consistently chooses not to do so.

Considering the high financial leverage at the parent company and the ambitious investment plans, we are surprised that Ørsted’s shareholders and debtholders have not forced Ørsted to disclose a parent company cash-flow statement, particularly when the group’s ability to fund its business model and ultimately its solvency is in question.

“Farm down” proceeds

On top of the divestment of a 50% ownership interest in Hornsea 3, Ørsted has highlighted two other key divestments: a 50% stake in Taiwanese Greater Changhua 2a and 2b projects, which we assume is done at the same multiple as Greater Changhua 4; and the potential full divestment of its EU onshore wind farm business, which we think will be easier to divest than offshore assets. Ørsted is hoping to generate proceeds of at least DKK35bn (£4.13bn) for these three transactions during 2025 – 2026. Additional contributions, predominately tax credits achieved in the US on Revolution Wind and Sunrise Wind projects, are expected of DKK15bn (£1.8bn).⁸³ We understand these would be paid in a lump-sum though recognised in the P&L as an annual contribution. To qualify for these credits, the two projects must be operational.

To generate the DKK35bn plus of proceeds, we estimate Greater Changhua 2 contributes DKK11.9bn (£1.41bn) (assuming a similar multiple achieved to the Greater Changhua 4 farm down) and EU onshore contributes DKK5.8bn (£680m). This means that 50% of Hornsea 3 must generate at least DKK17.3bn (£2.04bn). We think it unlikely that a stake in Hornsea 3 would be sold at a premium to book value, which means that £2bn can be raised when the project is 50% complete, with the additional £4bn of Capex being split 50/50 with the third-party investor, whilst Ørsted funds the transmission asset (c. £2.5bn) from working capital). There are many ways that a “farm down” of Hornsea 3 can be done but we have outlined what we believe is the most likely in view of the indications given by Ørsted as to its intentions. (See Fig. 32: Estimated Disposal Proceeds).

Fig. 32 | Estimated disposal proceeds

Return Free Risk

We think that Ørsted as a current investment proposition represents “return free risk” in that even if it executes its business plan without any further mishaps (which seems unlikely) then the stock already trades at book value when its investment projects deliver returns below any sensible cost of capital. ⁸⁴ Risks seem numerous, including:

1) overruns to ambitious capex plans over the next three years, 2) not being able to generate sufficient proceeds from the planned divestments of Hornsea 3, Greater Changhua 2 and the EU onshore business, 3) Not completing either US project and receiving the tax credit proceeds once the projects are operational, 4) higher debt financing costs, particularly if the credit ratings deteriorate with DKK10bn (£1.1bn) of bank and bond debt maturing in 2026⁸⁵ and 5) not generating sufficient Cashflow from Operations with weaker than expected cash generation. And as the rights issue prospectus notes:⁸⁶ “inadequate funding … could ultimately cause Ørsted to become unable to pay its debts.”

Given all the highlighted numerous risks – the company will likely be back raising more cash from equity investors, who will be left (again) holding the bag.

Conclusion: a goner with the wind

We have demonstrated through detailed calculations of profitability at the project level that Ørsted’s operational offshore wind assets would not be profitable without generous subsidies; that even with this government support, they make an anaemic return on capital; and that they also have hidden leverage and decommissioning liabilities, which are unfunded and could crystalise earlier than expected.

We have also attempted to forecast the profitability of the much larger projects Ørsted is currently developing, which we confidently forecast will be even less lucrative and subject to significant upwards revisions in capital costs; whilst lower subsidies mean that cash (EBITDA) profitability will be lower. All of this means that these key projects (Sunrise, Revolution, Hornsea 3) will take over a decade to become profitable at the EBIT level; and because their returns are significantly below any reasonable cost of capital assumption, they will destroy value for Ørsted investors. We are not surprised that Ørsted does not want to disclose this in their investor communications.

It is because offshore wind is so fundamentally flawed as an economic product (with low bang for buck return on capital and energy invested,⁸⁷ producing intermittent power that has low and diminishing value to the grid at high market shares)⁸⁸ that it rips off both consumers and investors alike and has a detrimental impact on the overall economy as finite resources are squandered. This is not just an Ørsted problem: in recent months, large offshore wind projects from Australia⁸⁹ to Japan⁹⁰ to the US have been cancelled as realisation has dawned that (to quote the current leader of the free world) “wind power doesn’t work – it’s unreliable, it’s expensive, it’s just not going to power our future.”⁹¹

Neither do we believe that Norwegian oil company Equinor (which has maintained a 10% stake in Ørsted)⁹² merging its offshore wind assets with Ørsted’s will solve these fundamental problems. It is sometimes said that a problem shared is a problem halved but, in this case, we think it would be a problem doubled. Any deal would just allow Equinor a face-saving exit from its own problematic offshore wind projects.

We noted previously that Ørsted’s focus on EBITDA (which excludes accounting for capital costs as an accounting metric of success even though the business model is highly capital intensive) can only be justified by the immaturity of its asset base, making the underlying profitability of projects difficult for current measurements of profitability at group level to reflect. We believe that Ørsted has pursued bigger, more value destructive projects, partly because if the quantum of growth and investment slowed, it would be more difficult for Ørsted to hide the lack of underlying profitability at group level.

We do not believe that there will be sustainable political will in the UK to revert to more generous CfD subsidies when its consumers already face the highest electricity prices in the world. The next UK general election (scheduled for 2029) will likely see a different government that may abolish ROC subsidies, scrap carbon taxes on power generation and renege on AR7 CfD awards, before any wind farms awarded in AR7 commence operation.

The appetite of third-party investors to buy into Ørsted’s developments has understandably diminished. Many of these investors could only make the sums work by financing their stakes with large quantities of then cheap debt, with Ørsted also offering to guarantee operating performance. And in the absence of dividends or “farm downs” it is now Ørsted shareholders who are left holding the bag.

The recent DKK60bn (£7.1bn) rights issue is not a one-time fix but a classic “extend and pretend.” Ørsted’s business model can never deliver for its investors because offshore wind is not economically viable for developers without subsidies and is not scalable (given the parasitical impact on the wider economy) with subsidies. Wind power is a backward technology which like Ørsted should be assigned to the economic dustbin of history.

Barry Norris
Alex Chatterton,
CFA, ACA
London, October 2025

Appendix 1

Snouts in the trough: a brief history of the UK subsidy regime

The UK subsidy regime before 2014, saw the wind farm developer granted a guaranteed premium via a Renewables Obligation Certificate (ROC), (typically a £100/MWh subsidy with inflation escalators on top of the market price) for 20 years (See Fig. 33: Average realised electricity price per fiscal year including ROC subsidy.) ⁹³

Fig. 33| Average realised electricity price per fiscal year including ROC subsidy ⁹⁴

This was subsequently replaced in 2014 by Contracts for Difference (CfD), whereby the wind operator was given a fixed price (or guaranteed a floor price until the CfD was switched on at their discretion) for 15 years (adjusted upward each year from a nominal 2012 price for inflation and grid charges) for electricity output. Quoting the CfD auction price in 2012 prices, supposedly making auction results comparative with previous outcomes, in our view misleads the public into believing that power is being supplied at much cheaper prices than in reality given upwards only price escalators (See Fig. 34: UK offshore wind subsidy development).

Whilst offshore wind projects have always been reliant on generous subsidies to be economically viable, as governments have tried to increase wind market share (of a technology which can no longer said to be experimental) overall subsidy payments have increased with volume but have necessarily become less generous on a MWh basis, which is crucial for project profitability. As (Fig. 34: UK offshore wind subsidy development) illustrates, headline auction prices fell from £147-150 MWh in AR0 in 2014 (in 2012 prices) to just £37.35 MWh in AR4 in 2022 (in 2012 prices) in which Hornsea 3 was awarded. This proved to be a vainglorious folly.

Fig. 34| UK offshore wind subsidy development⁹⁵

Upon taking Hornsea 3 final investment decision (FID) Ørsted then CEO Mads Nipper hailed offshore wind as “extremely competitive” though also admitting that the value creation for Ørsted was at the “bottom end” of 150-300bps over its cost of capital and that he intended to resubmit some Hornsea 3 capacity in subsequent auctions (which Ørsted subsequently did in AR6 in 2024 resubmitting 37.5% of theoretical future capacity at £54.23/MWh (in 2012 prices)).⁹⁶ Nevertheless, the average CfD for Hornsea 3, which we calculate as £59.78 (in 2024 prices), remains well below that awarded to Hornsea 2 (£80.1 in 2024 prices) and Hornsea 1 (£200 MWh in 2024 prices).

After AR4 in 2022, offshore wind auction prices began rising again. The subsequent AR5 auction in 2023 at the higher price of £44 MWh (in 2012 prices) failed to attract any bidder, whilst AR6 was awarded for new projects at £58.9 (in 2012 prices) in 2024. It is proposed that AR7 2025/6 will both increase the offshore award to £81/MWh (in 2012 prices) and lengthen the award period from 15 to 20 years. This is an increase of c.11% versus AR6.

It should be noted that a (2012) AR7 CfD price (after applying an inflation factor of 1.44) translates as £117/MWh (in 2025 prices). We estimate that this compares to the current cost of power generation from gas fired modern power stations (assuming current spot £29/MWh TTF gas and only 55% capacity utilisation) of £57/MWh (excluding £28 MWh of carbon taxes).⁹⁷ This award would also be above the (2025) AR2 price awarded in 2017 to Hornsea 2 of £80/MWh (2025 prices). Nowadays, even those who don’t understand the low value to the grid of intermittent power, no longer claim that offshore wind is “cheap.”

Appendix 2

Not Scalable: the political backlash

Britain currently has the highest electricity prices in the world, some three to four times those in the US. (See Fig. 35: UK Industrial Electricity Prices (incl. taxes)).

Fig. 35 | UK industrial Electricity Prices (incl. taxes) ⁹⁸

It is not hard to identify the problem: their electricity grid is powered by cheap and reliable gas, ours by expensive and unreliable wind. This abundance of cheap energy in the US manifests in Henry Hub gas (the benchmark price for US natural gas) currently trading at $3 per gigajoule (GJ). This compares with TTF gas (the European benchmark) at $10.8/GJ and crude oil at $11-12/GJ. By contrast, the 2024 UK offshore wind CFD auction was done at an energy equivalent of $31/GJ (subject to upwards only price revisions over the course of the 15-year contract)! (See Fig. 36: Energy Equivalent ($/GJ)).

Fig. 36 | Energy Equivalent ($/GJ) ⁹⁹

Whereas America powers its electricity grid with $14/GJ natural gas, the UK’s “Net Zero” plans are powered by offshore wind which is currently not only two times more expensive ($31/GJ) but also weather dependent, therefore not able to match demand, thus incurring additional eye-watering storage costs to be economically useful.

At the time of the 2008 Climate Change Act (which committed the UK to reducing CO2 emissions by 80% by 2050) the UK domestic electricity price was just £12/MWh. By the time of the 2019 amendment, which committed into statute “Net Zero” by 2050, the UK domestic electricity price was £18/MWh. Today, it is £36/MWh. (See Fig. 37: UK electricity price vs Renewable share).

Fig. 37 | UK electricity price vs Renewable share

Looking at it another way, before 2011, when the UK market share of “Renewables” first increased to above 5%, the average annual price increase for UK electricity over the previous 91 years had been just 2% per annum. The “Renewable” UK market share has subsequently increased to a reported 42%, whilst the average annual price increase since 2011 has been over 10% per annum (five times the average of the previous century). As the share of “Renewables” continues to increase so too will the UK’s electricity prices.
Although the Secretary of State for Energy Security and Net Zero, Ed Miliband, displays the zeal of a man who has just found his calling in life through membership of an apocalyptic cult, and we note AR7 is proposing to give significantly higher subsidies than AR6, we do not believe that the UK can revert to the level of CfD subsidies that would make offshore projects economically viable for investors. We think that the exorbitant rise in UK electricity prices since the 2008 Climate Change Act have been a significant cause of two decades of stagnant standards of living.¹⁰⁰ The political drive to “decarbonise the grid” is economically unsustainable and now politically unattainable.

We suspect that President Trump’s recently warning at the United Nations: “If you don’t get away from the “green scam”, then your country’s going to fail”¹⁰¹ was meant for UK Prime Minister Keir Starmer.

Glossary

• MW – Megawatt (unit of generation electricity)
• MWh – Megawatt hour (unit of use of electricity i.e. unit of power generated or consumed over time)
• GW – Gigawatt (1,000 MW)
• Opex – Operating expense
• Capex – Capital expenditure
• NPV – Net Present Value
• Cash Return on Investment – EBITDA / Invested Capital
• Return on capital employed – operating profit / capital employed
• CfD – Contracts for Difference
• EBIT – Earnings before interest and taxes
• EBITDA – Earnings before interest, taxes, depreciation and amortisation
• ROC – Renewables Obligation Certificates