Nodes for Socialization

Decarbonization is a problem of investment and economic coordination: real asset by real asset, we must rapidly transform global infrastructure stocks through twin programs of investment and divestment, building out the new system in tandem with winding down the old. Often, we must do so in ways that defy conventional considerations of profitability. And importantly, we must coherently sequence and coordinate such programs so as to prevent breakdowns in the ongoing operation of critical infrastructure systems and production and consumption networks.

This is all the more urgent in our increasingly turbulent global political context. In the face of rising economic, social, and political instability, populations around the world remain broadly in favor of decarbonization. Cascading climatic and political emergencies—as well as in the energy system—demand an ambitious and compelling alternative to climate breakdown. In order to move from slogans and proposals to action in the real economy, this alternative must present a concrete and far-sighted understanding of the investment hurdles and coordination problems involved in the green transition.

Where decarbonization is occurring outside China’s densely state-owned enterprise system, it typically involves increasing state intervention to mobilize capital from the financial sector by creating asset classes with sufficiently attractive risk-return profiles. As these developments have taken place, a debate has unfolded over the appropriate division of labor between state and capital—and the extent to which the dominant “derisking” strategy can reliably substitute for direct public investment through public ownership. Critics of derisking decry its tendency toward upward redistribution and doubt private capital’s ability to set the pace and shape of the transition at the appropriate scales. Defenders take a pragmatic approach, and argue that the magnitude of capital needed would be simply too politically difficult to divert back through the apparatus of state dirigisme. Many of the investment hurdles and bottlenecks constraining derisked private projects, they add, are not easily sorted across the public-private binary. Beyond these two positions, others consider the question of ownership orthogonal to that of the coordinating power of the regulatory state—standing in for the more salient question of policy making.

In what follows, we argue for what we term nodal socialization, outlining a framework for allocating public investment—and attendant ownership rights—under macrofinancial constraints. Given the practical unlikelihood of fully socializing the clean manufacturing and infrastructure apparatus, and the value of the functional critique of derisking’s efficacy vis-à-vis decarbonization, our framework identifies nodes whose socialization can tame the risk profiles of adjacent (private) projects in a manner that supports the larger program of decarbonization and macroeconomic stability without the regressive distributional politics implied by derisking.

We use as our starting point a case study of the UK’s energy system, whose Contracts for Difference program has been celebrated and imitated across Europe as an elegant model to derisk financing for private-led renewables development. But the model has suffered severe disruption to its investment pipeline amid the financial and supply chain turbulence of the last few years. Vulnerability on these fronts stems, on our account, from a decision-making structure that is (a) dependent on ex ante assurances of value capture created by a (b) fragmented landscape of actors.

To overcome these difficulties within the UK context, and more generally, we argue that key nodes within a given energy landscape—particularly the development of generation and transmission assets—can be socialized, reordering the structure of investment decision-making, rather than simply providing liquidity support at select hurdles.

UK context

The most significant buildout of the UK’s electricity sector took place during the postwar settlement, under the aegis of the nationalized Central Electricity Generating Board. But the presiding structural features of today’s regime date back to the 1989 Electricity Act, which laid the groundwork for the system’s privatization. The sectoral structure inherited from this legislation— vertically disintegrated, fully privatized, highly fragmented, and, consequently, reliant on atomized profit imperatives to coordinate the investment, divestment, and operation of assets across generation, transmission, and distribution—increasingly characterizes the power sector globally. Under this vertically disintegrated structure, generators compete in (overwhelmingly spot) wholesale markets to sell power to suppliers who in turn manage the consumer relationship. Separate actors own the transmission and distribution infrastructures that carry this electricity for a service fee.

This is the electricity regime within which decarbonization programs must take place. Since 2014, the country’s flagship Contracts for Difference scheme (CfD) has served as its primary decarbonization mechanism. The scheme guarantees generators a fixed price for electricity through government-run reverse auctions, with any differences between the negotiated price and the prevailing wholesale price of electricity financed through a backward-looking levy on electricity retailers. It is an elegant derisking regime that maintains competitive tension between developers while encouraging private investments by shielding them from merchant price risk—a sharp concern due to the volatility of wholesale markets.

Competitive tension is maintained through the auction’s notional “budget,” which limits the capacity that can be awarded contracts by capping the resulting amount that will land on consumer bills over the life of the contracts: effectively a multiple of capacity, load factors, and strike prices relative to forecast spot prices. The Government sets the “administrative strike price” (the reverse auction ceiling price) to target a given proportion of the supply curve as they imagine it to look, including based on their understanding of developers’ hurdle rates.

The CfD regime constitutes a strong state intervention into the UK electricity system that will transform its institutional architecture over time. As analyst Dieter Helm has argued, the state will become the central purchaser of all new electricity generation, functionally bypassing the wholesale market through Power Purchase Agreements. With a state monopsony de facto in place, the role of regulator Ofgem and private retailers in price discovery may virtually disappear.

Though the state is central, it is structurally circumscribed to backstopping private investment in renewable generation—abstaining from direct investment, divestment, and delivery itself. The regime relies on the state’s coordination, encoding, and enforcement capabilities in convening the auctions rather than its fiscal capacity.¹ Price risk, meanwhile, is eliminated for both generator and consumer via price-fixing with no absorption by the derisking state. The price mechanism maintains a coordinating role through competitive tension in the auction. But rather than a carrot or a stick, the intervention into the price signal is better understood as a temporal response to the particularities of renewable assets’ cost profiles by treating the price of its electricity less as the price of a current good than as the repayment of the capital good. Researcher Adam Khan has described this method of price-fixing as a hybrid regime that shields against risk at the expense of system responsiveness, acknowledging the inability of intermittent energy sources to respond to real-time price signals.

Contracts for Difference proved very successful at catalyzing investment in capital-intensive technologies like offshore wind until 2022. That year, the UK’s offshore wind capacity was second only to China in absolute terms, and only to Denmark on a per capita basis. Allocation Round 4 (AR4), as late as July 2022, secured as much as 7 GW of offshore capacity, up from 5.5 GW in 2019’s AR3. The pretax cost of capital is estimated to have been reduced 130 basis points (roughly equivalent to a 7 percent fall in the levelized cost of electricity) by the elimination of merchant risk alone, not to mention the technology’s maturation from its erstwhile frontier status.

Headwinds

In “de-risking” one set of investment risks—reducing exposure to wholesale market volatility through the creation of regulated auctions and contracts—for for-profit developers, however, the program leaves these same private investment decisions vulnerable to another set of risks: cost. Interest rates rose by 4–5 percentage points during 2022–23 (a 2ppt addition to the cost of capital adds 20 percent to the renewable levelized cost of energy, or LCOE, by IEA estimates. Turbine sale prices (roughly a third of LCOE when including capital costs) also spiked dramatically amid the wider inflationary episode—invariably 20–40 percent between 2021 and 2022 for onshore turbines—exacerbated by supply chain snarls. These cost hikes are impervious to the public-private distinction, and their impact on investment plans depends on the structure of the market.

In the CfD framework, cost increases dramatically derailed the UK’s investment pipeline in offshore wind. 2023’s AR5 infamously failed to secure any bids to build offshore wind, while developers sought to renege on the terms of existing AR4 contracts. (Some of the latter spent months at risk of complete abandonment until revived by new buyers.) Both the price ceiling in the new allocation rounds and the strike price locked in place through existing AR4 contracts were deemed too low by private developers in the face of surging costs to warrant moving ahead with new projects. The government’s refusal of industry pleas to raise the AR5 price ceiling was motivated in part by suspicion—exacerbated by glaring informational asymmetries—that their cost complaints were a bluff.

The latest round, after the government raised the ceiling by 67 percent and the notional “budget” by 50 percent, still secured less offshore wind capacity than AR3, with one third of it attributable to the deferral and renegotiation of some AR4 projects under the “permitted reduction” clause. This process leaves half the capacity of derailed AR4 projects unrecovered. Just recently Ørsted announced the cancellation of Hornsea 4, which counted for nearly half of the auction’s total secured offshore wind capacity, citing “supply chain costs, higher interest rates, and an increase in [delivery] risk.” Similar dynamics have led private developers to wage a capital strike in the context of the US’s nascent offshore wind sector. Such incidents suggest that an anatomy is needed to better understand the types of risk that these capital projects face, and how the larger system is able to metabolize them.

Value capture within a fragmented landscape

When for-profit developers halt investment in response to rising costs, they demonstrate that the profitability and certainty on which private investment depends is impacted by more variables than the CfD process can control. Not enough of the project is derisked. But the regime’s brittleness in the face of turbulence is a result of what we call its dependency structure: that is, which aspects of a project are conditional upon or informed by which others, on what terms. In the case of CfDs, the ex-ante criterion for securing investment is bundled with the ex post means of recouping the costs that materialize in the intervening years, in the form of the fixed strike price. This has implications both for the robustness of the project investment case, and for sustaining a healthy supply chain.

Between the moment at which the strike price is agreed and when it begins to be paid out to developers sits a multi-year delivery phase during which the cost side of the profitability equation (not smoothed by any derisking policy) can experience turbulence.² An emerging consensus expects volatility in project costs to become more the norm than the exception going forward. To quote the credit rating agency Fitch, (our emphasis): “In some markets, wind energy developers and turbine producers operate under fixed-price contracts for their output. However, there are often time lags before costs are locked in.” It is exposure to precisely that volatility that Ørsted emphasized when it listed “supply chain and cost inflation” as its number one business risk looking ahead to 2024.³

Hence even the most sophisticated advocates for the CfD regime are careful to stipulate a “stable macroeconomic context” as a condition for its efficacy. Absent this, the inflexibility core to its success exposes it to circumstantial deteriorations in profitability. This circle can only be squared by incorporating a risk premium into a fifteen-year strike price that is not paid until after most of those cost risks (around 70 percent of the LCOE) have already been resolved. This would mean calcifying yesterday’s uncertainties into tomorrow’s prices for fifteen years at time.

Within this decentralized decision nexus, the underfunding of CfD auctions periodically bemoaned by green advocates clearly appears as a feature rather than a bug: there to induce competitive tension and thus cost discipline by making workable strike prices—the derisking instrument—artificially scarce. Looking at the CfD program as a whole, we can see a quadrilemma between the certainty of investment, the quantity of capacity invested in, cost discipline in its delivery, and private ownership.

Supply chain

The implications of the dependency structure we’ve outlined extend beyond the power system itself and into the supply chain. In the context of distributional struggle between the power generators and their input manufacturers, there is a tension between maintaining profitability of generation and production while pushing for the lowest possible consumer costs of generation through contract auction models. This leaves the sector vulnerable to shocks. The fragmented allocation process increases the sensitivity of generator investment-decision making to costs and has thus foisted risk onto, for example, wind turbine manufacturers. As reverse auction rounds have been organized around lower and lower strike prices in recent years, for-profit developers have pushed their input producers, such as wind turbine manufacturers, to reduce their prices, in turn exacerbating their sensitivity to their input costs. Thus, the commodity price shocks wrought by Covid-19 and the Russia-Ukraine war did not hit a robust production network struggling to expand, but one simply struggling to maintain capacity.

Since 2020 European and American manufacturers have seen margins fall despite rising turbine sale prices. (Chinese manufacturers have enjoyed the opposite on both counts.) The extent of price increases by turbine manufacturers were shaped by this exogenous shock, but achieving a productive base capable of meeting power sector decarbonization targets is clearly in tension with organizing the entire chain of production and generation around private profitability and minimal consumer prices.

Furthermore, in the context of a long-cycle industry, ex ante price-fixing creates a chicken-and-egg problem between the investment decisions of the developers and the supply chain: developers calibrate their price-fixing to how cheaply they think they can source inputs from a supply chain whose own investments in manufacturing are premised on demand expectations. Ironically, it was precisely to the extent that CfDs provided the supply chain with a robust order flow, rather than merely foisting risk onto it, that the program also drove reductions in delivery cost (per MW) through “resource mobilization”: “ensur[ing] a strong pipeline of projects that enables the supply chain to prepare” by investing in both R&D and expanded capacity. A great deal of cost reductions were achieved through ever larger turbines, while greater vessel fleets have made installation and commissioning quicker and cheaper. Array cables and foundations got cheaper too. Now that costs have risen, manufacturers are also squeezed by strike prices. Vestas recently cites “developers cancelling or pausing offshore projects due to business cases uncertainty” as a key source of risk for the manufacturing industry, alongside “severe permitting delays [and] volatility in electricity market policy.”

The unstable relationship between developers and the supply chain is an illustration of how derisking one node in the productive nexus can reorder and absorb risk for adjacent nodes.

System coherence

A fundamental feature of the CfD regime’s structure as we’ve characterized it is that the ex ante criterion for securing investment is assessed at the level of the isolated project, separated from the value it creates as part of a larger, real-time grid balanced power system. There ought to be a distinction between the project-level and system-level evaluation of the hurdle rate, in order to accurately assess what financial flows can be netted. In energy markets in particular, system fragmentation results when coordination through prices collapses into infra-system distributional conflict—among and between generators, retailers, and the grid.  These frictions are heightened not only as the intermittent-centric system becomes increasingly complex, but as we navigate the mid-transition challenge of simultaneously managing ongoing system operation with the buildout and operation of the new system.

Distributional conflict also arises between generation and transmission, particularly when plant developments apply to the grid for transmission connections. The grid’s opaque process for apportioning the costs of the grid upgrades required for those connections leads many developers in the US and the UK to respond by “playing the table”—submitting speculative projects for transmission connections in the hope that one proves financially attractive, while the rest can be abandoned. As a result, in the UK the National Grid’s Transmission Entry Connection Register is bloated with ultimately spurious applications, creating administrative bottlenecks, and potentially impeding the buildout of network capacity relative to the generation that needs transmission.

Far from being merely pecuniary, these distributional conflicts have the effect of stymying the investment pipeline and in some cases throwing sand into the gears of ongoing system operation. The growing pains of the emergent renewables-centric regime has given rise to a proliferation of new—often highly gameable—market mechanisms to manage its unreliability. Dispatchable gas plants sells ever less power into wholesale spot markets but remain a vital fallback for episodes of high demand, dunkelflaute, or grid congestion (whereby transmission capacity is insufficient to carry renewable power to demand centers from its remote sources); “capacity markets” have been created to reconcile this system-level need with the financial burden of their diminishing capacity utilization by paying them to remain on standby. Layered on top of this is a system of constraint payments during congestion events to induce, at one end, the frustrated renewable plants to curtail production and, on the other, standby gas plants nearer demand spots to boot up and replace them. The exigencies of real-time grid balancing conspire with privatized fragmentation during these moments to confer acute market power to gas plants, allowing them to extract rents far beyond the physical cost of booting up. Operating through this byzantine interlacing of price mechanisms, the “bribe to capital formation,” as Paul Samuelson termed the derisking move, degenerates into the bribe to simple capital operation.

These dysfunctions reflect the enormous task of incrementally grafting together two incongruous systems, with distinct logics of investment and of operation, all the while coordinating fragmented profit-seeking agents via a cluster of (some fixed, some floating) price mechanisms. The evolving hybridity of this regime will continue to produce spasms that variously derail investments and burden consumers. The renationalization of the balancing authority (previously a subsidiary of National Grid plc) under the new name of National Energy System Operator signals the UK’s explicit albeit belated recognition that a physically coherent clean power system demands centralized coordination, but that insight is yet to extend to the relations of exchange that produce it.⁴ Charged with drawing up the blueprint of the future system—the Strategic Spatial Energy Plan—the organization remains structurally powerless to enact its designs. Coordination in this sense is hypothetical. Eliminating transaction costs by subsuming the power system onto a larger balance sheet can rationalize the formation and operation of component assets under a single coherent logic.

Derisking the supply chain by socializing energy assets

Our analysis illustrates the advantages of the public development of renewable capacity in imposing rationality on the clean power transition—with spillover stabilization effects for the adjacent consumption and production networks feeding in and out of the electricity system.

Core to this proposition is the unique ability of a public developer to reorder the dependency structure of the investment function, by pursuing investment projects on the basis of system-level need and setting prices ex post to recoup delivery costs after their attendant uncertainties have resolved—rather than proceeding by providing ex-ante assurances of project-level profitability. Meanwhile, cost discipline throughout the system can be preserved through competitive supply chain tendering. The terms on which this investment is ensured would prove easier to reconcile with the ongoing mid-transition operation of the system (e.g. curtailment events), while stability benefits also extend to an orderly managed fossil fuel phaseout.

This is not a suspension of the profit imperative but its subordination to social need. It is also distinct from simply providing liquidity support to overcome particular hurdle rates for private investment.

Its relationship to manufacturers is where nodal socialization becomes relevant, situating the power system as one node within the larger system of economic production and consumption. Providing a large, robust order flow would facilitate investment, as in greater vessel fleets or turbine manufacturing capacity. Just as importantly, rationalizing this order flow would help tame erratic cycles of investment and disinvestment, over- and under-capacity, fluctuating prices, and demand that characterize a heavy industry where demand and supply respond to each other at a significant lag. This is especially important given that the capitalization of these costs will persist into energy system prices for decades to come, undermining popular consent to decarbonization.

Our analysis is concerned with what public development can do in the immediate term to ameliorate frictions in our energy system, especially in relation to private production and investment.

In this proposed regime, it is through public investment that private investment is derisked, not in the sense of redistributing or assuming risk, but in the sense of reducing it absolutely—avoiding the canonical derisking pitfalls of privatizing reward while socializing risk. Symmetrically, the rationalization of real-time system operation redounds to the benefit of lower and more stable electricity prices for end users, delivering macroeconomic stabilization through the channel of a systemically significant price. This stability will in turn have the second-order effect of stabilizing the investment environment for clean energy.