The Case for Ambitious Public Ownership of Renewable Generation: Ten Common Questions and Common Wealth’s Answers

How public ownership of new renewable capacity can accelerate the energy transition.
This research is published in collaboration with the following organisations:
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The Case for Ambitious Public Ownership of Renewable Generation: Ten Common Questions and Common Wealth’s Answers

How public ownership of new renewable capacity can accelerate the energy transition.
Executive Summary

The accompanying report to this Q&A can be read here.

[.num-list][.num-list-num]1[.num-list-num][.num-list-text]Renewables have seen significant structural decreases in cost and are now widely considered to be cost competitive if not cheaper than fossil fuelled power. Why, then, would public direct investment be necessary to meet clean generation capacity targets?[.num-list-text][.num-list]

Renewable electricity generation in general and solar photovoltaics in particular have indeed benefitted from structural declines in cost, as measured in the Levelised Cost of Energy (LCOE) — explained in footnote.1 Simply put, this cost decline is an industrial policy success story.  Where utility scale wind and solar farms were uneconomic compared to coal and gas generation in the early 2000s, state subsidy induced investment in global context led to technology improvements and economies of scale that led to cost reductions on the manufacturing and project development sides such that the LCOE of renewables has reached general parity with fossil fuels. Here it is important to note the structural role of subsidies or derisking regimes and the distinction between cost and the profitability needed to secure private investment.  

As we argue in the report, despite their lower LCOEs, renewables struggle in wholesale markets such as Britain’s as they are highly capital intensive (especially compared to fossil fuel generation) and structurally vulnerable to both merchant price risk–sensitive to volatility in terms of debt servicing —and the “revenue cannibalisation effect”, whereby periods of high output and low demand produce very low marginal prices for variable renewable electricity, causing extremely low or negative market prices that also pose debt servicing and solvency issues. To overcome this sensitivity to capital costs and market risks, investment in for-profit utility scale renewable generation relies on state subsidisation tools that provide a guaranteed price or otherwise employ public funds to furnish stable profitability.  

Therefore, we agree with the geographer Brett Christophers, who concluded in a global study of renewable project financing:

[.quote][.quote-text]In the first and last instance, capitalism is about profit. The reason that private-sector lenders and investors are hesitant about supporting renewable power projects in the absence of state supports or corporate PPAs is that the expected financial returns are highly uncertain. In actively derisking the development of renewables, a subsidy or a PPA provides the likelihood, if not necessarily the certainty, of profitability. It is one thing for the state to effectively outsource to the private sector responsibility for doing things that are socially or ecologically desirable, and which the state could in theory — and historically often has in practice — undertake itself. If rapidly building a carbon-free energy-generation infrastructure is one such thing, others include the provision of healthcare, education, clean water, affordable housing and so on. But it is another thing entirely for the state to effect such outsourcing in a context where the ability of the private sector to reliably and consistently generate profit is constrained.2[.quote-text][.quote]

In our report, we stress that the UK is not on course through status quo policies to deliver on its clean generation targets and we demonstrate the structural fragility of its derisking regime for relying on ex ante fixed prices to induce private investment which are inflexible to ex post changes in circumstance. In the face of such sluggish investment and structural fragilities in derisking regimes, direct public investment through public enterprise is necessary to meet generation targets. Public enterprises face no mandate to pay dividends and benefit from structurally lower cost of capital — a cost to which renewables projects in particular are acutely sensitive — and do not stipulate subjective hurdle rates in excess even of these costs as a condition for going ahead with socially-needed investments. A publicly-owned energy company would be able to more rapidly and decisively invest in renewable generation while delivering lower costs at both project and system wide levels. 

Moreover, cost reductions can themselves pose delivery risks, as we have seen in recent months in the offshore wind sector. As has been widely reported in the financial press, reverse auction models such as the UK’s Contracts for Difference Scheme have induced cost reductions for offshore wind projects in part because developers have pushed for input cost reductions from manufacturers, which in turn made the underlying supply chain brittle and vulnerable to shocks.3 This dynamic is essential to understanding input cost inflation and auction failures.  

Finally, as Nolan Lindquist, executive director of the Center for Active Stewardship, has argued, the cost reductions that solar and onshore wind farms have benefitted from are not guaranteed to continue and not guaranteed to happen at all for all technologies, offshore wind in particular: “Not every industry we need to scale to decarbonise our economy will have a high enough learning rate to reach cost competitiveness with incumbent, fossil-fuel-based technology. And in some cases, the experience curve concept may not apply at all, given it is better suited for thinking about routinised manufacturing processes than site-specific mega-projects.”4  

[.num-list][.num-list-num]2[.num-list-num][.num-list-text]In the UK, private direct investment, supported by state subsidy and derisking has already brought clean energy capacity online. Wouldn’t direct public investment risk disturbing the functioning of the current delivery regime at the expense of meeting clean generation targets?[.num-list-text][.num-list]

The UK energy mix has indeed seen marked renewable penetration. As CarbonBrief recently reported, in the UK:

[.quote][.quote-text]Electricity from fossil fuels has now fallen by two-thirds (199TWh) since peaking in 2008. Within that total, coal has dropped by 115TWh (97 per cent) and gas by 80TWh (45per cent). These declines have been caused by the rapid expansion of renewable energy (up six-fold since 2008, some 113TWh) and by lower electricity demand (down 21 per cent since 2008, some 83TWh). As a result, fossil fuels made up just 33 per cent of UK electricity supplies in 2023 their lowest ever share of which gas was 31 per cent, coal just over 1 per cent and oil just below 1 per cent. Low-carbon sources made up 56 per cent of the total, of which renewables were 43 per cent and nuclear 13 per cent. The remainder is from imports (7 per cent) and other sources (3 per cent), such as waste incineration. Overall, the electricity generated in the UK in 2023 had the lowest-ever carbon intensity, with an average of 162g of carbon dioxide per kilowatt hour (gCO2/kWh).5[.quote-text][.quote]

However, it is important to measure this relative to the generation capacity requirements of power sector decarbonisation targets. Indeed, the majority of necessary capacity has yet to be built and must be built on a much more rapid timeframe than existing capacity came online, making the necessary investment sprint different in kind than previously built clean generation capacity. In the report, we demonstrate that the UK is not on course to deliver clean generation targets through the status quo policy regime, which structurally relies on state attempts to derisk private investment at the abstention of direct public investment in renewable capacity. We identify structural limitations of this approach in general and of the Contracts for Difference Scheme in particular that hinder and stand to further impede power sector decarbonisation.  

First, relying solely on private investment means that investment is guided by project level profitability as opposed to a comprehensive investment programme to build out a functioning renewable electricity system. Not every project or investment necessary to building and operating a functioning clean grid will be sufficiently profitable, even with state subsidy. This issue will gain greater salience as renewable share of electricity capacity deepens, as the most obviously or assuredly profitable projects will have been invested in first.  

Second, the fragmented and asynchronous investment decision-making regime has failed and will continue to fail to properly sequentially coordinate investment, which is critical for building a functioning renewable electricity system and preventing both upstream and downstream inflationary frictions or delivery bottlenecks in interrelated production and consumption networks in the process.

Third, and moving away from private investment in the context of wholesale markets in general, there are structural limitations and fragilities in the design of the Contracts for Difference Scheme (CfD) that have derailed and will continue to derail necessary investment.  

The CfD scheme stands as the UK’s current renewable capacity investment policy regime. To militate against merchant price risk, the state offers a fixed power-purchase agreement that guarantees a stable and certain revenue stream backstopped by state support. It is a way of taking risk out of private investment, operating as a bribe to induce private capital expenditure.  

And yet on its own terms, the CfD programme is insufficient for creating and coordinating investment in clean energy generation. The scheme’s reverse auction process only indirectly sets an overall target for energy generation capacity. This is to be achieved each round, without a mechanism to set a floor for energy generation capacity, nor to coordinate system-wide sequencing of the renewable projects needed. Moreover, precisely in relying on an ex ante fixed price to induce private investment, this regime is highly sensitive to ex post changes in circumstance, which poses key tensions.  

First, it is difficult to respond flexibly to external shocks when relying on private profit-seeking investors whose fixed capital investment decisions are dependent on assurances given long before. An approach which sets electricity prices based on average actual costs, as we argue a public enterprise like Great British Energy (GBE) could do, would allow for greater resilience of investment, especially during periods of turbulence, which further climate destabilisation and geopolitical volatility are likely to bring.

Second, in the middle of a cost-of-living crisis, there is a tension between maintaining profitability of both private generation and private production in the supply chain while pushing for the lowest possible consumer costs of generation through contract auction models, leaving the sector vulnerable to shocks.  The fragmented allocation process has foisted risk onto the wind turbine manufacturers who, from a strategic perspective, are most in need of guarantees from the state.

Third, as September’s auction failure points to, there is a more fundamental issue with relying on private investment which the CfD Scheme is highly sensitive — it is subject to subjective hurdle rates, or expected rates of return, to meet generation capacity targets. The Department for Energy Security and Net Zero assumes an 8.3 per cent return on investment for offshore wind for the most recently announced strike price. We do not know if September’s failed £44 strike price would have actually been loss-making — only that it was not deemed profitable enough for investors, with profitability defined by internally set hurdle rates and relative to other market and investment activities.

Therefore, we stress the structural necessity of public direct investment in renewable generation through public enterprise. Moreover, in terms of the potential risk of counterproductive disruption that such systemic restructuring might pose we would also stress four interrelated points.  

First, rapidly transforming the physical infrastructure and capital stocks that compose the Britain’s electricity system is existentially imperative to halt climate destabilisation, adapt to locked in change, and address the current and prevent future cost of living crises; disruption is a sober reality. The question is not disturbance or not, it is what interventions will deliver what is necessary. We argue that public coordination, premised on public investment and ownership is necessary to overcome the fragmentation of ownership and privatisation (and therefore profit imperative bound nature) of investment decision-making throughout the electricity system. Socialising the investment decision function through the capacity to undertake direct investment in renewable energy generation is essential for delivering power sector decarbonisation targets.

Second, the status quo policy regime, if roughly maintained, would still entail and/drive a substantive restructuring of Britain’s power sector architecture. We agree with Dieter Helm, who notes that functionally speaking, through the CfD Scheme, “the state has become the central purchaser of almost all new generation. Generators now compete for contracts from government” which structurally bypass the wholesale market for electricity.13 Put differently, CfDs are essentially indirect public procurement contracts for private renewable generation capacity, and their continued use will likely have transformative effects on the wholesale market. Indeed, if CfDs come to generate the majority if not all of the UK’s electricity — as is the status quo plan, although only at the beginning of such a programme with RO assets still comprising the majority of renewable generation online — this scheme raises serious questions about the future of the for-profit retail supply sector and its regulator OFGEM, as the state would organically develop into a de facto if not de jure monopsony buyer of electricity.  

Likewise, alongside the creeping bypass of the wholesale market and development of the state as de facto central buyer through CfDs, the government has already begun to (in our view, weakly) socialise grid balancing and system-wide investment planning function through the nationalisation of National Grid’s Electricity System Operator — which performs real-time grid balancing functions — and announced its intention to develop it into a publicly-owned “Future System Operator.” This FSO would have an expanded charge to proactively plan the development of Britain’s electricity and gas systems. However, this socialisation is partial and therefore not wholly effective, as we detail in the main report.

Moreover, we already see and can further anticipate calls within the sector for increased administrative strike prices and other public subsidies to deliver investment in the transition while seeking to maintain price and broader macroeconomic stability.

Third, our recommendations do not eschew private activity and indeed should be viewed as a more effective regime for derisking and stabilising private investment and activity in green and in greening production networks. We expand this point in response to the next question.  Even if private capital could be induced to invest at necessary scale, this approach to investment delivery will still be more far more expensive than direct public investment and would further represent an immense opportunity cost of thwarting social wealth building. For example, based on savings from interest alone, before accounting for savings from not paying dividends to shareholders, a stock of debt of £8.3bn (Labour’s initial capitalisation of GB Energy) would save between £150-200m per year, while £28bn stock of debt would save £420-700m per year (based on the difference between the cost of borrowing for the UK Government compared to the cost of BBB rated corporate bonds typically used to finance offshore projects).

Finally, there is the fundamental point that we are at a critical juncture in the transition. Before us lies an epochal choice. Down one route is a roadmap from the past. Just as we privatised the development of the petro-carbon wealth of the North Sea in the 1980s — and with it squandered the potential to build and retain durable and large-scale sources of public wealth — so an approach today that employs market coordination to chart the transition will be slower, less fair and more expensive. It will fail to nurture the wealth of the commons for common benefit. But another route is possible: through ambitious public enterprise and coordination we can harness the wind and the waves and the sun — nature’s bounty — to develop shared and sustainable public wealth. Let us not make the same mistake again.

[.num-list][.num-list-num]3[.num-list-num][.num-list-text]What would be the division of labour between public and private capital were a new public enterprise to undertake the majority of investment in clean generation capacity?[.num-list-text][.num-list]

The state has been essential at every turn to facilitating the construction of the UK’s existing renewable generation capacity. Yet, the role of the state in power sector decarbonisation has to date been circumscribed to employing fiscal resources and the state’s singular risk-bearing capacity to backstop or otherwise subsidise private investment in renewable generation and auxiliary infrastructure, abstaining from direct investment and undertaking itself. This division of labour between the state and private capital leaves the coordination of power sector decarbonisation to the market, meaning it is premised on private and asynchronous decision making to undertake fixed capital investment and broader economic activity based fundamentally on expectations of profit; it is precisely for these reasons the UK is not on track to meet power sector decarbonisation targets. Ultimately, the build-out of renewable energy will be paid for by the public, whether through public subsidy, higher consumer energy bills to for-profit companies, or direct investment undertaken by the state itself. Thus, the question is how do we want to use the state, its singular risk bearing capacity, and public money.

Our recommendation is for a systemic role for public enterprise in delivering clean generation targets. Structurally unimpeded by the profit imperative, a publicly-owned energy company would be able to more rapidly, strategically and decisively invest in renewable generation while delivering lower costs at both project and system-wide levels. Functionally, this would socialise the investment decision function through the capacity to undertake direct investment in renewable energy generation. However, we stress that precisely in socialising the investment decision function, our proposal constitutes a reorganisation of the division of labour between state and private capital that not only does not foreclose private activity in renewable generation but should rather be viewed as a more effective regime for derisking and stabilising private investment and activity in green and in greening production networks.  

In simplified, functional terms, our recommendations would see the state take on the functions of a project developer but in so doing may draw on the capacities of existing for-profit developers through a reorganised relationship. Where CfDs are an indirect public procurement mechanism, we detail how, especially early in its institutionalisation, an entity like Great British Energy could run direct competitive procurement auctions for bids to build public generation assets as the best route to clean energy security. This alternative approach would immediately deploy private building capacity backed by the certainty of socialised investment decision-making. Public direct investment and operation of renewable generation capacity is the most robust mechanism to support investment and resilience in the power sector and beyond. Direct public investment in clean generation can support the stability of its supporting supply chains — likely to be private for-profit production — better than private generation, as it can invest with greater certainty —  regardless of shocks or profitability considerations —  and without pushing for maximum reductions in input costs at the expense of supply-chain stability. To this effect as well, the greater certainty of a state-led green transformation of the power sector will functionally de-risk investment to electrify other sectors, such as industrial production. Moreover, both because public investment benefits from structurally lower costs than private investment and because public ownership allows for socially and flexibly setting electricity prices, a green investment sprint by a new public entity that comes to own the majority of generation capacity will support a green industrial strategy and greater macroeconomic resilience. Indeed, in terms of public sector net worth, public ownership that in this case governs investment in and the operation of a systemically significant sector or input such as electricity provides both policy manoeuvre room and economic resilience capacity that exceeds tidy accounting of liabilities versus revenue by assets.  

In terms of what constitutes direct public investment or ownership, we feel that passive stakes of majority-private owned projects are insufficient for meeting delivery of capacity targets and will not offer the same benefits of structural public ownership of generation that we evidence in this report. Therefore, while not precluded from taking partial equity stakes in projects, the modus operandi of the clean generation enterprise must be direct majority ownership, undertaking the majority of necessary investment across all technologies. Ownership stakes at 51 per cent of projects is the minimum necessary to assume control rights over day-to-day operations, which bring the many of the coordination powers we have stressed, for example procurement. We note a tradeoff between outright ownership — with full coordination, income, and pricing control rights — and a 50+1 approach that would enable an ambitious GBE-style vehicle to capitalise and operate a larger portfolio of projects more quickly. The imperative is that ownership structure enables a systems level approach to investment and maximal control of operation of assets at the system level.

[.num-list][.num-list-num]4[.num-list-num][.num-list-text]Realising the transformative and muscular public enterprise you propose would entail/require building state capacity — which is a difficult and hardly overnight task. Will we be able to build such public capacity and is it worth attempting to?[.num-list-text][.num-list]

To repeat an earlier point, rapidly transforming the physical infrastructure and capital stocks that compose Britain’s electricity system is existentially imperative to halting climate destabilisation, adapting to locked in change and broader biospheric destabilisation, and addressing the current and prevent future cost of living crises; the necessity of building state capacity is a sober reality. The first step in the political and practical processes of building state capacity is acknowledging this reality — its existential stakes — and acting in light of it.

[.num-list][.num-list-num]5[.num-list-num][.num-list-text]You propose a muscular public enterprise; Labour has likewise pledged to use GBE to make the UK into a clean energy superpower. What kind of capitalisation and scale would this require? Likewise, why should GBE be allocated a significant portion of Green Prosperity Plan funding in the event of a Labour government?[.num-list-text][.num-list]

Modelling by the TUC estimates that to turn GBE into a national clean energy champion equivalent to EDF — which produces around three-quarters of all domestically generated energy in France (418 of 549 TWh in 2021) - and make Britain a genuine “clean energy superpower” will require between £114-£153 billion of investment up to 2040. Assuming that a similar proportion of that investment would be sourced through a combination of equity and debt financing as with existing renewables developers across Europe (both public and private), it is estimated that GBE would need public capital investment allocation of £61.4-82.3 billion over that period. As the TUC argues Public Power: turning it into reality, a new public energy champion will best succeed if that capital allocation - at least £40 billion of investment – is frontloaded in the first half of the decade. Over time, a public company can continue to self-finance investment through its own bond issuance and revenue reinvestment.”

Capitalisation for investment should come from two main sources: Labour’s proposed Green Prosperity Plan (GPP), building over time on the party’s initial £8.3bn capitalisation, matched to off-balance sheet investment (principally the UK Infrastructure Bank (UKIB), which is mandated to invest in infrastructure finance to tackle climate change and support regional growth across the UK).  

While the overall figure represents a significant investment (reflective of the ambition of the goal), it is important to put it in context: for example, Boris Johnson’s government had an initial capital injection of £12 billion to UKIB, as well as up to £10 billion of government guarantees, with its final capacity being £22 billion.

A public renewables company should get a sizeable (but still minority) share of a public investment programme like Labour’s Green Prosperity Plan because electricity is a core economic input across the economy, as well as a fundamental right and requirement for wellbeing and participation in society. Maintaining low and stable prices for electricity through public investment and coordination is imperative for in turn maintaining macroeconomic stability, especially in the face of the potential shocks posed by a context of geoeconomic turbulence and the effects of locked in climate destabilisation. To this effect as well, maintaining the lowest and most stable possible prices for electricity will be key to supporting a green industrial strategy in the UK. Politically, it can also help ease a very visible expression of the cost of living crisis: energy bills.

[.num-list][.num-list-num]6[.num-list-num][.num-list-text]Your case for an ambitious public enterprise that undertakes the majority of necessary clean electricity investment points to recent failures of the Contracts for Difference Scheme. In response to these failures and/or to prevent further issues with the scheme, couldn’t the state merely boost the CfD Scheme’s administrative strike price and/or provide sources of subsidised public financing or grants to support private investment? Likewise, wouldn’t green credit guidance or dual rates solve present issues?[.num-list-text][.num-list]

Relying solely on private investment in general and the Contracts for Difference Scheme in particular poses structural limitations that hinder and stand to further impede power sector decarbonisation. This is because fragmentation of investment decision-makers, the discipline of the profit imperative, and specific to CfDs, an inflexibility to ex post changes in circumstance constrain investment decision-making. Changes to the CfD structure or operations such as increased strike price, larger subsidisation budgets both for and beyond the scheme, and reform to more directly set a capacity target for allocation rounds may in the near term induce more private investment. However, these suggestions do not address the structural issues, meaning they will prove limited in the overall task of delivering total power sector decarbonisation targets.  

Similarly, we see public financing and credit guidance as limited tools. In arguing for chartering a public generation company, we draw a clear distinction between fixed capital investment and financing or funding of said investment — and a distinction between the public institutions that might serve or support each function. Through public banking the state may extend or through credit guidance seek to induce the private extension of favourable credit, this economic activity is distinct from undertaking fixed capital investments, let alone operating capital assets at scale or for extended time periods. Such tools still leave investment-decision making to a distinct second actor undertaking capital investment. We see a role for both the UKIB and the Bank of England to support financing in the renewable sector — both GBE and private developers — but caution against viewing public financing and credit guidance as sufficient. In particular, it is worth emphasising the end of easy money has demonstrated the ambivalence of green monetary policy.  On the one hand, renewables benefitted greatly from the era of low interest rates. Renewable energy is capital intensive and sensitive to interest rate rises, especially in comparison to fossil fuels. Therefore, increases in interest rates disincentivise private investment in renewable generation. Moreover, the era of low interest rates (and thus lower yield on safe assets) generated the private portfolio glut’s greater relative need for yield-bearing assets, which pushed structural interest in private infrastructure investment. Yet, this period of low interest rates and state derisking regimes still did not see sufficient renewables investment to meet power sector decarbonisation targets. Therefore, while raising interest rates has actively harmed private investment, lowering them is not sufficient to meet system-wide targets.  

A strategic state holding company such as Labour’s proposed National Wealth Fund could make equity investments in generation or transmission infrastructure with more substantive equity share, but its asset management and operations functionality would likewise still be limited in comparison with a public corporation. The National Wealth Fund could more maximally be used to capitalise a public enterprise and house it on its balance sheet. In the main report, we provide an institutional sketch that favours the creation of a stand-alone off-balance sheet independent enterprise. Ultimately, it is Common Wealth’s view that regardless of whether the public generation enterprise is housed by a holding company or is set off balance sheet, it will need to take the form of a public enterprise qua enterprise — not ad hoc equity stakes or assets on the holding company’s balance sheet.  More generally, the NWF is better suited as a strategic equity investor to coordinate green supply chains and industrial decarbonisation than as the coordinator of the electricity system.  

Some proposals for a public energy company in the UK context look much closer to a public development bank or a wealth fund than a public generation enterprise as we have proposed, in particular by only supporting high risk assets or technologies and through only partial equity stakes in projects. We agree with the TUC, who note that such a limited approach will lead to too cautious investment, as safer investments cannot balance riskier ones in a portfolio. This would mean “socialising the risks of technology development, while leaving proven profits to the private sector.”22 Moreover, such weak institutionalisation would fail to fulfil the criteria of socialising the investment function for clean generation — which as we have stressed is necessary across all technologies — and does not offer the financial and operational benefits that we detail in the report.  

The financial benefits we detail are rooted in the structurally lower cost of building new generation through public direct investment as opposed to private investment and in the perpetual public control over price setting. Public ownership, and public ownership alone, offers truly zero marginal cost renewable electricity once capital costs are recouped.  

Our claims on the superior operational and coordination benefits of public ownership over private for-profit ownership are rooted in the coordination power a systemically significant public enterprise would enjoy over electricity system-wide investment planning, supply-chain or industrial planning, and over time, provision of electricity.

[.num-list][.num-list-num]7[.num-list-num][.num-list-text]Given the transformative role for public enterprise this report advances, how would this proposal change or affect institutional arrangements such as the role of OFGEM or the Future Systems Operator and the structure of wholesale markets?[.num-list-text][.num-list]

We acknowledge that such a potential transformation within the sector raises further questions around the evolution of power sector architecture. However, we stress that the power sector architecture is already in flux in the face of the decarbonisation imperative and broader dysfunctions in its systemic design. Ultimately, this report is primarily concerned with demonstrating that creating and empowering a public generation enterprise such as GBE is ultimately the best answer to the question of how to deliver transformation of the UK electricity system: by divorcing investment decision-making from the profit imperative and delivering such investment at structurally lower cost.  

The status quo renewable generation investment regime, which relies on the Contracts for Difference Scheme would on its own terms represent a restructuring of the power sector’s architecture, with similar questions currently left unanswered. For, over time, the state would become the de facto monopsony buyer of electricity from a fragmented set of private for-profit generation firms, bypassing the wholesale market with fixed-price power purchase agreements throwing into question the future role of supply companies. In our proposal, there is a similar functional bypassing of the wholesale market and for-profit supply companies with the benefit of both socialised and system integrated investment-decision making and ongoing operation of assets. If coupled with public ownership of the grid, as we argue in a companion report, our proposals would entail de facto reintegration of the electricity system under public ownership, regardless of nationalisation of supply companies.  

Consolidating the control rights of these currently structurally disparate generation assets into the hands of a coherent authority offers ongoing operational and coordination benefits beyond just generation investment decisions. On the face of it, organising the operation of a variable renewables-based system — both through and after the process of building it — through fragmented private ownership and markets is absurd. Under current arrangements, both investment in system-level generation capacity (for what is currently a fossil-gas dominated hybrid renewables gas system) and operation of assets — including curtailment — to meet grid balancing is done not through direct asset coordination but through the price mechanism — more concretely, payments to asset operators financed out of higher customer prices. Integrating the system within the public firm removes the need to indirectly attempt to cohere the action of private assets around the real time project of grid balancing through pricing, especially if public generation is coupled with public ownership of the grid.

Further questions concerning the evolution of the power sector architecture — such as institutional arrangements, the role of OFGEM and DZNETZ, and wholesale market redesign — ultimately flow downstream from how robust this institutionalisation will be, in terms of its mandate and whether its capitalisation and design support the institution’s delivery of it.

We give this reply not to punt the question, but to note that these questions are similarly raised and left unanswered by current status quo policy and our proposals and to stress relative flexibility in our views. There are many possible permutations of institutional arrangements that are of second order importance to the problems this report is concerned with and the recommendations it offers.

[.num-list][.num-list-num]8[.num-list-num][.num-list-text]How would an entity like GBE be governed, operated and financed? How would it decide what projects or technologies to invest in?[.num-list-text][.num-list]

As is best practice among other successful national energy companies, the generator should be a limited liability company with the state the sole shareholder (with the company owned on behalf of the public) Capitalised initially through Treasury-issued gilts to maximise cost of capital savings for upfront investment (£30 billion over five years) and/or taxation to fund public investment, the energy company should nonetheless sit off the state’s balance sheet and have operational independence to pursue its mandate and objectives. Co-investment from public financial institutions like the UK Investment Bank or British Business Bank should support the company investing £40 billion in its first five years (in total over the next Parliament: £30 billion direct investment; £10 billion from these institutions). Going forward, it should have independent borrowing powers, as other public energy companies possess. The company’s governance should reflect the fact is owned and operates by and for the public; we recommend a tripartite structure with a technical board, an executive board and a stakeholder citizens board.

We recommend that the company has three main divisions. Each division would draw on technical expertise related to their sectors and areas of focus:  

  • Mature: A division focused on rapidly scaling mature technologies, primarily through building and operating new wind and solar capacity (including generation and related transmission, distribution and storage needs);
  • Frontier: A division focused on accelerating the deployment of frontier generating technologies as well as ancillary technologies like energy storage, demand side response, long duration storage, and hydrogen;
  • Community: A division focused on supporting community clean power initiatives.  

Operationally, a public renewables company should develop and deploy a balanced portfolio of mature and frontier technologies as it seeks to lead the sprint to a net-zero grid by 2050 at the latest. In pursuit of that goal, it should invest up to £150 billion by 2040. Excessive focus on frontier technologies, many of which are not expected to come online until the 2040s at the earliest, will do little to decarbonise the grid in the near-term or reduce our exposure to volatile fossil fuels; it also risks creating potential cashflow vulnerabilities and leaving the company excessively reliant on public capital injections, as frontier technologies will likely not yield regular income in the coming decade. Conversely, a singular focus on mature technologies risks missing out on unproven but potentially critical new technologies and supply chains of the future, and would miss out on the benefits of investing in derisking and scaling up nascent technologies and the deployment of flexible low-carbon technology. Nonetheless, given the imperative to hit fast-approaching clean power targets — and the need to exponentially expand renewable generation in the decades thereafter — proven technologies should form the majority of the company’s portfolio, at least in its first decade.

[.num-list][.num-list-num]9[.num-list-num][.num-list-text]What would the first hundred days of a new public company look like?[.num-list-text][.num-list]

  • A new government legally charters a renewable generation company – in the case of a Labour government, GBE - with the aforementioned mandate and endows it with initial capitalisation in its first major fiscal event. The governing board should be constituted with a mix of world-leading experience in renewables development, for example it could seek to hire from the leadership pool of Vattenfall, Orsted, or equivalents, as well as technical and public expertise. It should reaffirm intention to meet 2030 power sector decarbonisation target through public enterprise.
  • Immediate charter with robust capitalisation of a GBE-style vehicle will be essential in ensuring it can begin to take institutional form and operations early in the new government, in line with meeting power sector decarbonisation targets. Reaffirming political, whole of government, intent to reach 2030 power sector decarbonisation through public enterprise will provide necessary certainty for investments throughout the UK economy.
  • Hire technical experts in both electricity planning, project development, and operations of renewables assets.
  • Developing a skilled workforce will be essential for the successful delivery of the mandate. There is a great deal of capacity in terms of knowledge and technical expertise found in the private sector’s current labour force, and making jobs at the company competitive with private developers and electricity operators will be essential to both kickstarting initial projects and longer-term building a robust institutional knowledge and broader capacity base.
  • In order to kickstart transition and begin process of building a portfolio of assets and contain sectoral prices, bring ROE assets into public ownership.
  • As the report discusses, bringing existing ROE assets into public ownership would have an immediate effect on electricity prices. Such price deflation would build political support for a new public generator. Moreover, it would provide both an immediate revenue base and a set of assets through which to build operational expertise.
  • Announce a handful of initial investments, which should include at least one project cancelled by private developers, to replan as public projects by the new public enterprise.
  • This can be done as a reverse auction akin to CfD but not around strike price but development cost bid. We argue that picking up a project that the private sector refused to complete would be a simple route to initial project development and would have great political effect, signalling the significance of the new institution and power sector decarbonisation goals.  
  • Initiate process of creating 5-year plan for systemwide rollout that includes electricity system mapping along with planning labour force needs.
  • This can be iteratively done in consultation with other public institutions such as the UK CCC and DESNZ, but will be critical for charting both the company’s initial investment paths but coordination economy wide investments and decarbonisation capacity such as labour training and input production.

[.num-list][.num-list-num]10[.num-list-num][.num-list-text]Would this not remove competition and with-it incentives for efficiency and cost reductions?[.num-list-text][.num-list]

This report acknowledges that competition in renewable generation has led to steep technological cost reductions but stresses that low cost does not induce for-profit investment and that the current organisation of competition and risk produce supply chain vulnerability and pose investment and delivery risk. Our proposal would rearrange competition in some areas, but in a manner that better insures investment delivery and production network resilience.  

As Brett Christophers has demonstrated, the commonly used metric Levelised Cost of Electricity (LCOE) to compare the cost price of electricity generation sources is a misleading benchmark for for-profit investment decision-making, meaning competition to reduce cost is not guaranteed to generate investment. First, the LCOE “attempts to render technologies comparable by discounting all costs to the present (as a so-called ‘overnight cost”), but, nonetheless, a plant where essentially all costs are incurred upfront is, in economic terms, nothing like a plant where costs are spread broadly equally over thirty years, even if they happen to have the exact same LCOE. Whereas 80 to 90 per cent of the LCOE of wind and solar plants represents upfront investment, the equivalent proportion is only around 40 to 50 per cent in the case of coal-fired plants and it is lower still — as little as 20 per cent — in the case of natural gas, for which fuel costs (approximately 70 per cent) predominate. Thus, increases in the cost of key construction like steel and aluminium, which as occurred in 2021, are … far less consequential for these less capital-intensive fuel-based generating technologies. The key point, then, cannot be overemphasised: understood as aggregations of expenses, fossil-fuel based plants and renewable based plants are entirely different economic phenomena.”6 Moreover, competition and price reduction within generation itself poses structural investment risk for renewables. Marketisation of generation, that is to say the organisation of generation around competitive and fragmented wholesale markets, induces greater price-competition, but in so doing moves “away from a model in which there exists substantial capacity for the industry to capture and profit from cost reductions.” Due to the cost structure of renewables, lower technology cost and price competition within wholesale markets can therefore disincentivise for profit investment. And of course, as discussed above, renewable penetration in the context of competitive wholesale markets can lead to revenue cannibalisation effects.  

In the UK, the current for-profit renewables investment derisking regime attempts to organise competition and price reduction while dederisking against merchant-price and revenue-cannibalisation risk and in the wholesale market. In the Contracts for Difference model, reverse auctions retain competition among bidding generators while mitigating merchant-price risk in the wholesale market with an ex ante fixed price. Yet, this model still leaves investment decision-making to the whims of private investors subject to the profit imperative and more broadly produces corrosive effects within the wider production network that can later erode the functioning of this same derisking apparatus. In the case of offshore wind, competition amongst bidders in CfD reverse auctions has pushed developers to demand cost reductions from input suppliers which has eroded the manufacturing base and the use of an ex ante fixed price has left investment delivery inflexible and thus vulnerable to supply-side and interest rate shocks.  

Therefore, we stress that technology cost reduction and efficiency are desirable, but must be organised in a manner that is subordinated to or supports investment delivery and resilience of the sector. In our proposal, Great British Energy socialises investment decision-making in the sector but may still support competition and efficiency through competitive procurement processes to secure building services and support resilience by managing the burden of risk and price competition within the input production chain.  

Cover image licensed to Angus Wilson under creative commons (CC BY-NC-ND 2.0 DEED)

Full Text
The Case for Ambitious Public Ownership of Renewable Generation: Ten Common Questions and Common Wealth’s Answers

[#fn1][1][#fn1] Levelised cost of electricity (LCoE) is a financial measurement tool used to asses and compare alternative methods of electricity generation against one another from a cost perspective. Simply put, it refers to the average cost of building an operating an electricity generating asset against the per unit total of electricity it is expected to generate across an assumed lifetime. In the context of wholesale markets, one may also understand the LCoE as the average minimum price at which the electricity generated by the asset is required to be sold in order to recoup the total costs of production over its lifetime.

[#fn2][2][#fn2] Brett Christophers, “Bringing Renewables to Market: Prospects for the After-Subsidy Energy Transition”, The 2021 Antipode RGS-IBG Lecture, 2022.

[#fn3][3][#fn3] Will Mathis, “Renewable Power’s Big Mistake Was a Promise to Always Get Cheaper”, Bloomberg, 7/11/2022. Available here.

[#fn4][4][#fn4] Learning Curves, Phenomenal World. Available here.

[#fn5][5][#fn5] Carbon Brief, Analysis: UK Electricity from Fossil Fuels Drops to Lowest Levels Since 1957. Available here.

[#fn6][6][#fn6] Brett Christophers.“The Price is Wrong: Why Capitalism Won't Save the Planet”, Verso, forthcoming 2024.