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Distributed photo-voltaic (PV) generation is one of the pillars of energy transitions around the world, but its deployment in the distribution grid requires costly reinforcements and expansions. Prosumage – consisting of a household-level PV unit coupled with a battery storage system – has been proposed as an effective means to facilitate the integration of renewable energy sources and reduce distribution grid stress. However, tapping its full potential requires regulatory interventions; otherwise, system costs could rise despite increasing flexibility. We analyze the effectiveness of different policy schemes to mitigate the need for distribution capacity expansion by incentivizing beneficial storage operation. Our novel top-down modeling approach allows analyzing effects on market prices, storage dispatch, induced distribution grid requirements, system costs, and distributional implications. Based on German power system data, numerical results indicate that distribution grid requirements can be reduced through simple feed-in policies. A uniform limit on maximum grid feed-in can leave distribution system operators better off, even if they fully compensate prosumage households for foregone revenue. Policies imposing more differentiated limits at the regional level result in only marginal efficiency improvements. Complete self-sufficiency (autarky) is socially undesirable, as it confines important balancing potential and can increase system costs despite adding storage.

Kazakhstan envisions a transition towards a green economy in the next decades, which poses an immense challenge as the country's economy and energy system depends heavily on hydrocarbon resources. Here, it lacks inclusive and transparent tools assessing technical, economic, and environmental implications resulting from changes in its electricity system. We present such a tool: our comprehensive techno-economic unit-commitment model determines the hourly least-cost generation dispatch, based on publicly available data on the technical and economic characteristics of the system. It accounts for particularities of the Kazakh electricity system by representing combined heat and power, and endogenously determining line losses. Model results examine two typical weeks: winter (annual peak load) and summer (hour of lowest annual load) presenting regionally and temporally disaggregated results for power generation, line utilization, and nodal prices. In an application to market design, the paper compares nodal and zonal pricing as two possible pricing schemes in Kazakhstan for the envisioned strengthening of the day-ahead market. The model analyze the current Kazakh electricity system and can be easily expanded to assess the sector's future development. Possible applications include investment in generation and transmission infrastructure, policy assessment for renewables integration, carbon pricing, emission reduction, and questions of market design.

The achieved international consensus on the 1.5–2 °C target entails that most of current fossil fuel reserves must remain unburned. A major contribution has to come from coal as both the most abundant and the most emission-intensive fuel. Currently, a majority of climate policies aiming at reducing coal consumption are directed towards the demand side. In the absence of a global carbon-pricing regime, these policies are prone to carbon leakage and other adverse effects. Supply-side climate policies present an alternative and increasingly discussed approach to reduce the consumption of fossil fuels. In this article, I employ a numerical model of the international steam coal market to examine two supply-side policies that are currently discussed in academic literature and by policy-makers, alike: (1) a production subsidy reform introduced in major coal-producing countries and (2) a globally implemented moratorium on new coal mines. The model simulates global patterns of coal supply, demand, and international trade, with endogenous investment in coal production and transportation capacities. I find that mere production subsidy removal, while associated with a small positive total welfare effect, leads to a minor reduction of global emissions. By contrast, a mine moratorium induces a much more pronounced reduction in global coal consumption by effectively limiting coal availability and strongly increasing prices. Depending on the specification of reserves, the moratorium can induce a coal consumption path consistent with the 1.5–2 °C target.

The shift away from coal is at the heart of the global low-carbon transition. Can governments of coal-producing countries help facilitate this transition and benefit from it? This paper analyses the case for coal taxes as supply-side climate policy implemented by large coal exporting countries. Coal taxes can reduce global carbon dioxide emissions and benefit coal-rich countries through improved terms-of-trade and tax revenue. We employ a multi-period equilibrium model of the international steam coal market to study a tax on steam coal levied by Australia alone, by a coalition of major exporting countries, by all exporters, and by all producers. A unilateral export tax has little impact on global emissions and global coal prices as other countries compensate for reduced export volumes from the taxing country. By contrast, a tax jointly levied by a coalition of major coal exporters would significantly reduce global emissions from steam coal and leave them with a net sector level welfare gain, approximated by the sum of producer surplus, consumer surplus, and tax revenue. Production taxes consistently yield higher tax revenues and have greater effects on global coal consumption with smaller rates of carbon leakages. Questions remain whether coal taxes by major suppliers would be politically feasible, even if they could yield economic benefits.

This paper presents a general electricity-CO $$_{2}$$ modeling framework that is able to simulate interactions of the energy-only market with different forms of national policy measures. We set up a two sector model where players can invest into various types of generation technologies including renewables, nuclear power and carbon capture, transport, and storage (CCTS). For a detailed representation of CCTS we also include industry players (iron and steel as well as cement), and CO $$_{2}$$ transport and CO $$_{2}$$ storage including the option for CO $$_{2}$$ enhanced oil recovery (CO $$_{2}$$ -EOR). The players maximize their expected profits based on variable, fixed and investment costs as well as endogenous prices of electricity, CO $$_{2}$$ abatement cost and other incentives, subject to technical and environmental constraints. Demand is inelastic and represented via type hours. The model framework allows for regional disaggregation and features simplified electricity and CO $$_{2}$$ pipeline networks. It is balanced via a market clearing for the electricity as well as CO $$_{2}$$ market. The equilibrium solution is subject to constraints on CO $$_{2}$$ emissions and renewable generation share. We apply the model to a case study of the UK electricity market reform to illustrate the mechanisms and potential results attained from the model.

The deployment of battery-powered electric bus systems within the public transportation sector plays an important role in increasing energy efficiency and abating emissions. Rising attention is given to bus systems using fast charging technology. This concept requires a comprehensive infrastructure to equip bus routes with charging stations. The combination of charging infrastructure and bus batteries needs a reliable energy supply to maintain a stable bus operation even under demanding conditions. An efficient layout of the charging infrastructure and an appropriate dimensioning of battery capacity are crucial to minimize the total cost of ownership and to enable an energetically feasible bus operation. In this work, the central issue of jointly optimizing the charging infrastructure and battery capacity is described by a capacitated set covering problem. A mixed-integer linear optimization model is developed to determine the minimum number and location of required charging stations for a bus net...

The Trump administration has promised to stop the spiraling down of the U.S. coal industry that has been going on for several years. We discuss the origins of the decline of the U.S. coal industry and new policy interventions by the Trump administration. We find that a further decrease of coal consumption in the U.S. electricity sector must be expected because of the old and inefficient U.S. coal-fired generation fleet. By contrast, we adapt the EIA’s overly optimistic view and analyze three potential support schemes to assess whether under such assumptions they can turn the tide for the U.S. coal industry: i) revoking the Clean Power Plan (CPP); ii) facilitating access to the booming Asian market by developing West Coast coal export terminals; and iii) enhanced support for the Carbon Capture, Transport and Storage (CCTS) technology to provide a long-term perspective for domestic coal use while mitigating climate change. We investigate the short-term and long-term effects for U.S. coal production using a comprehensive partial equilibrium model of the world steam coal market, COALMOD-World (Holz et al. 2016). Revoking the CPP will stop the downward trend of steam coal consumption in the U.S., but will not lead to a return of U.S. coal production to the levels of the 2000s with more than 900 Mtpa. Even when assuming a continuously strong global coal demand and expanding U.S. coal export capacities, U.S. coal production will not return to its previous production highs. When global steam coal use, including U.S. consumption, is aligned with the 2°C climate target, U.S. steam coal production drops to around 100 Mtpa by 2030 and below 50 Mtpa by 2050, respectively, even if CCTS is available and exports via the U.S. West Coast are possible.

With Germany's nuclear phase-out, 23 reactors need to be dismantled in the near future. Initiated by the difficult financial situation of affected utilities in 2014, a major discourse on ensuring financial liability led to a redistribution of liabilities and finances, with the utilities remaining in charge of dismantling, while liability for interim and final storage now transferred to the public. This paper assesses whether the new regulation is ultimately likely to be to the benefit of the public. It introduces a two-stage stochastic optimization framework encompassing the different dismantling phases, resulting waste flows and storage levels of low- and intermediate-level waste (LLW and ILW) as well as the associated costs. Results show that storage risk – proclaimed as a major barrier to efficient decommissioning – is not a major driver for the optimal decommissioning schedule. However, a delay of ten years might increase interim storage costs now borne by the public by over 20%. Lacking experience and handling capacity of the industry could significantly shrink the buffer currently included in utility funds in order to deal with dismantling uncertainties. Our analysis reveals the storage gate as the new crucial interface between utilities and the public storage provider.

The European Union has embarked on the transformation of its energy and electricity system to low-carbon energy sources, just like Germany and many other countries. This chapter analyzes the European strategy for low-carbon transformation in relation to specific aspects and features of the German energiewende. Due to the different preferences, objectives, and institutional settings of decision-making processes in Germany and Europe, lessons from the German context are not directly applicable to the European context and vice versa. While some lessons apply to both—such as the German experience with ambitious CO2 reduction targets—others do not, such as the potential role of coal and nuclear energy in the longer-term energy mix. The chapter begins with a brief survey of European energy (and later climate) policies going back to 1951, with the decisions to establish the European Community for Steel and Coal (ECSC) and subsequently Euratom in 1957. Section 10.2 covers the creation of the European internal market in the 1990s and its application to the energy sectors (mainly electricity and natural gas); it also covers more recent discussions, such as the energy and climate package to 2020, the 2030 targets, and the parallel discussion about longer-term orientations up to 2050. Sections 10.3, 10.4, and 10.5 analyze the three pillars of European transformation towards a low-carbon energy system: coal with CO2 sequestration, nuclear power, and renewables. In this context, we discuss a major difference between the European transformation to a low-carbon economy and the German energiewende: The two energy sources that Germany has banned from its energy mix, coal and nuclear, are still high on the European agenda. Meanwhile, the potential of renewables has been systematically underestimated in European scenario documents, due mainly to an overestimation of costs and an underestimation of the technical potential. Section 10.6 then compares two alternative scenarios for a low-carbon transformation in Europe: one is the EU Reference Scenario, which is based on the traditional triad of coal (with CCTS), nuclear, and renewables. In the other scenario, based on our own modelling work, neither CCTS nor nuclear are available at a reasonable cost and renewables carry the major burden of decarbonisation. Section 10.7 concludes.

Distributed photo-voltaic (PV) generation is one of the pillars of energy transitions around the world, but its deployment in the distribution grid requires costly reinforcements and expansions. Prosumage - consisting of a household-level PV unit coupled with a battery storage system - has been proposed as an effective means to facilitate the integration of renewable energy sources and reduce distribution grid stress. However, tapping its full potential requires regulatory interventions; otherwise, system costs could rise despite increasing flexibility. We analyze the effectiveness of different policy schemes to mitigate the need for distribution capacity expansion by incentivizing beneficial storage operation. Our novel top-down modeling approach allows analyzing effects on market prices, storage dispatch, induced distribution grid requirements, system costs, and distributional implications. Numerical results for German power system data indicate that required distribution grid requirements can be reduced through simple feed-in policies. A uniform limit on maximum grid feed-in can leave distribution system operators better off, even if they fully compensate prosumage households for foregone revenue. Policies imposing more differentiated limits at the regional level result in only marginal efficiency improvements. Complete self-sufficiency (autarky) is socially undesirable, as it confines important balancing potential and can increase system costs despite adding storage.

Both in the German energiewende and in the European low-carbon energy system transformation, infrastructure is generally considered as a conditio sine qua non: a necessary though not sufficient condition for a low-carbon economy—and one without which energy transformation may fail. At second glance, there may be some doubt as to whether “big infrastructure” is really the appropriate way to approach the low-carbon transformation. The main reason is that in a carbon-intensive energy system, more infrastructure automatically implies more carbon emissions (sometimes called “carbon lock-in”). In this chapter, we analyze the role of physical infrastructure in the European low-carbon transformation, with a special focus on large-scale transmission infrastructure for electricity, natural gas, and CO2. Although these infrastructures can play a certain role, they are not necessarily the critical factors in low-carbon transformation, and often low-cost measures such as improving regulation or tightening access rules are more effective than capital-intensive infrastructure expansion. Section 11.2 suggests that although a majority of authors see infrastructure development as a no-regrets option, there are also arguments against an oversupply of infrastructure. Sections 11.3–11.5 provide model- and case study-based analyses of different infrastructure sectors. Section 11.3 focuses on electricity transmission and compares the plans for pan-European electricity highways with other, more modest scenarios focusing on domestic upgrades and selected cross-country interconnectors. Section 11.4 is dedicated to natural gas infrastructure: Our results show no evidence of a substantial need for additional pipeline or LNG infrastructure, but rather a need for modest investment, given the diverse and global European supply of natural gas. Our analysis of infrastructure planning for carbon pipelines in Section 11.5 yields an even more striking result: Perhaps not a single cross-border pipeline may be required—except for perhaps a few in the North Sea—simply because the underlying technology, carbon capture, transport, and storage (CCTS), is unlikely to be used at the expected scale. Our conclusion in Section 11.6 is that the way forward is more likely to lie in regional and local cooperation in infrastructure.

Kazakhstan envisions a transition towards a green economy in the next decades which poses an immense challenge as the country heavily depends on (hydro-)carbon resources, for both its economy and its energy system. In this context, there is a lack of comprehensive and transparent planning tools to assess possible sustainable development pathways in regard to their technical, economic, and environmental implications. We present such a tool with a comprehensive techno-economic model of the Kazakh electricity system which determines the hourly least-cost generation dispatch based on publicly available data on the technical and economic characteristics of power plants and the transmission infrastructure. This modeling framework accounts for the particularities of the Kazakh electricity system: i) it has a detailed representation of combined heat and power, and ii) line losses are endogenously determined using a linear approximation. Model results are examined for a typical winter week (with annual peak load) and a typical summer week (with the hour of lowest annual load) presenting regionally and temporally disaggregated results for power generation, line utilization, and nodal prices. In an application to market design, the paper compares nodal and zonal pricing as two possible pricing schemes in Kazakhstan for the envisioned strengthening of the day-ahead market. In general, the model can be readily used to analyze the least-cost dispatch of the current Kazakh electricity system and can be easily expanded to assess the sector's development. Among others, possible applications include investment in transmission lines and in the aging power plant fleet, scenarios and policy assessment for emission reduction, and questions of market liberalization and market design.

In this paper, we develop a model to analyze the economics of carbon capture, transport, and storage (CCTS) in the wake of expected rising CO2 prices. We present a scalable mixed integer, multiperiod, welfare-optimizing network model for Europe, called CCTS-Mod. The model incorporates endogenous decisions on carbon capture, pipeline and storage investments, as well as capture, flow and injection quantities based on given costs, CO2 prices, storage capacities, and point source emissions. Given full information about future costs of CCTS-technology, and CO2 prices, the model determines a cost minimizing strategy on whether to purchase CO2 certificates, or to abate the CO2 through investments into a CCTS-chain on a site by site basis. We apply the model to analyze different scenarios for the deployment of CCTS in Europe, e.g., under high and low CO2 prices, respectively. We find that beyond CO2 prices of €50 per t, CCTS can contribute to the decarbonization of Europe’s industry sectors, as long as one assumes sufficient storage capacities (onshore and/or offshore). We find that CCTS is only viable for the power sector if the CO2 certificate price exceeds €75 per t.

Scenarios of future energy systems attribute an important role to Carbon Capture, Transport, and Storage (CCTS) in achieving emission reductions. Using captured CO2 for enhanced oil recovery (CO2-EOR) can improve the economics of the technology. This paper examines the potential for CO2-EOR in the North Sea region. UK oil fields are found to account for 47% of the estimated total additional recovery potential of 3739 Mbbl (1234 MtCO2 of storage potential). Danish and Norwegian fields add 28% and 25%, respectively. Based on a comprehensive dataset, the paper develops a unique techno-economic market equilibrium model of CO2 supply from emission sources and CO2 demand from CO2-EOR to assess implications for a future CCTS infrastructure. The demand for “fresh” CO2 for CO2-EOR operation is represented by an exponential storage cost function. In all scenarios of varying CO2 and crude oil price paths the assumed CO2-EOR potential is fully exploited. CO2-EOR does add value to CCTS operations but the potential is very limited and does not automatically induce long term CCTS activity. If CO2 prices stay low, little further use of CCTS can be expected after 2035.

Based on a review of the current state of the Carbon Capture, Transport and Storage (CCTS) technology, this paper analyzes the layout and costs of a potential CO2 infrastructure in Europe at the horizon of 2050. We apply the mixed-integer model CCTS-Mod to compute a CCTS infrastructure network for Europe, examining the effects of different CO2 price paths with different regional foci. Scenarios assuming low CO2 certificate prices lead to hardly any CCTS development in Europe. The iron and steel sector starts deployment once the CO2 certificate prices exceed 50 € /tCO2. The cement sector starts investing at a threshold of 75 € /tCO2, followed by the electricity sector when prices exceed 100 €/tCO2. The degree of CCTS deployment is found to be more sensitive to variable costs of CO2 capture than to investment costs. Additional revenues generated from utilizing CO2 for enhanced oil recovery (CO2-EOR) in the North Sea would lead to an earlier adoption of CCTS, independent of the CO2 certificate price; this case may become especially relevant for the UK, Norway and the Netherlands. However, scattered CCTS deployment increases unit cost of transport and storage infrastructure by 30% or more. This is the preprint of an article published in Energy Journal , available online at: https://doi.org/10.5547/01956574.37.SI3.poei

The deployment of battery-powered electric bus systems within the public transportation sector plays an important role to increase energy efficiency and to abate emissions. Rising attention is given to bus systems using fast charging technology. This concept requires a comprehensive infrastructure to equip bus routes with charging stations. The combination of charging infrastructure and bus batteries needs a reliable energy supply to maintain a stable bus operation even under demanding conditions. An efficient layout of the charging infrastructure and an appropriate dimensioning of battery capacity are crucial to minimize the total cost of ownership and to enable an energetically feasible bus operation. In this work, the central issue of jointly optimizing the charging infrastructure and battery capacity is described by a capacitated set covering problem. A mixed-integer linear optimization model is developed to determine the minimum number and location of required charging stations for a bus network as well as the adequate battery capacity for each bus line of the network. The bus energy consumption for each route segments is determined based on individual route, bus type, traffic and other information. Different scenarios are examined in order to assess the influence of charging power, climate and changing operating conditions. The findings reveal significant differences in terms of needed infrastructure depending on the scenarios considered. Moreover, the results highlight a trade-off between battery size and charging infrastructure under different operational and infrastructure conditions. The paper addresses upcoming challenges for transport authorities during the electrification process of the bus fleets and sharpens the focus on infrastructural issues related to the fast charging concept.

The achieved international consensus on the 1.5‐2°C target entails that most of current fossil fuel reserves must remain unburned. Currently, a majority of climate policies aiming at this goal are directed towards the demand side. In the absence of a global carbon regime these polices are prone to carbon leakage and other adverse effects. Supply‐side climate policies present an alternative and more direct approach to reduce the consumption of fossil fuels by addressing their production. Here, coal as both, the most abundant and the most emission-intensive fuel, plays a pivotal role. In this paper, I employ a numerical model of the international steam coal market (COALMOD‐World) to examine two alternative supply‐side policies: 1) a production subsidy reform introduced in major coal producing countries, in line with the G20 initiative to reduce global fossil fuel subsidies; 2) a globally implemented moratorium on new coal mines. The model is designed to replicate global patterns of coal supply, demand and international trade. It features endogenous investments in production and transportation capacities in a multi‐period framework and allows for substitution between imports and domestic production of steam coal. Hence, short‐run adjustments (e.g. import substitution effects) and long‐run reactions (e.g. capacity expansions) of exporting and importing countries are endogenously determined. Results show that a subsidy removal, while associated with a small positive total welfare effect, only leads to an insignificant reduction of global emissions. By contrast, a mine moratorium induces a much more pronounced reduction in global coal consumption by effectively limiting coal availability and strongly increasing prices. Depending on the specification of reserves, the moratorium can achieve a coal consumption path consistent with the 1.5‐2°C target.

To achieve the three main energy policy priorities of competitiveness, energy security and decarbonization, the UK government has recently undertaken a major “Energy Market Reform” (EMR). This paper presents a modeling framework to analyze how the different policy measures of the EMR will shape the future UK electricity generation mix until 2050. We set up a two-sector model where players can invest in various types of generation technologies including renewables, nuclear, and Carbon Capture, Transport, and Storage (CCTS). For a detailed representation of CCTS we also include industry players (iron/steel as well as cement), CO 2 transport, and CO 2 storage including the option for CO 2 -enhanced oil recovery (CO 2 -EOR). The players maximize their expected profits based on variable, fix and investment costs, as well as the price of electricity, CO 2 abatement, and other incentives, subject to technical and environmental constraints. Demand is inelastic and represented via a selection of representative hours. The model framework allows for regional disaggregation and features simplified electricity and CO 2 pipeline networks. The model uses a mass balance as market clearing for electricity and CO 2 . The equilibrium solution is subject to constraints on CO 2 emissions. In this paper we present the model formulation and some preliminary results to illustrate the mechanics of the model. The tentative scenario indicates a diversified technology mix for 2050. The CCTS development is purely triggered by CO 2 -EOR; the EMR does not incentives any additional CCTS investments.

In this paper we investigate the introduction of an export tax on steam coal levied by an individual country (Australia), or a group of major exporting countries. The policy motivation would be twofold: generating tax revenues against the background of improved terms-of-trade, while CO2 emissions are reduced. We construct and numerically apply a two-level game consisting of an optimal policy problem at the upper level, and an equilibrium model of the international steam coal market (based on COALMOD-World) at the lower level. We find that a unilaterally introduced Australian export tax on steam coal has little impact on global emissions and may be welfare reducing. On the contrary, a tax jointly levied by a "climate coalition" of major coal exporters may well leave these better off while significantly reducing global CO2 emissions from steam coal by up to 200 Mt CO2 per year. Comparable production-based tax scenarios consistently yield higher tax revenues but may be hard to implement against the opposition of disproportionally affected local stakeholders depending on low domestic coal prices.

This paper presents a general electricity-CO2 (ELCO) modeling framework that is able to simulate interactions of the energy-only market with different forms for national policy measures. We set up a two sector model where players can invest into various types of generation technologies including renewables, nuclear and Carbon Capture, Transport, and Storage (CCTS). For a detailed representation of CCTS we also include industry players (iron and steel as well as cement), and CO2 transport and CO2 storage including the option for CO2 enhanced oil recovery (CO2-EOR). The players maximize their expected profits based on variable, fixed and investment costs as well as the price of electricity, CO2 abatement cost and other incentives, subject to technical and environmental constraints. Demand is inelastic and represented via a selection of type hours. The model framework allows for regional disaggregation and features simplified electricity and CO2 pipeline networks. The model is balanced via a market clearing for the electricity as well as CO2 market. The equilibrium solution is subject to constraints on CO2 emissions and renewable generation share. We apply the model to a case study of the UK Electricity Market Reform to illustrate the mechanisms and potential results attained from the model.

In its Green Paper on a 2030 framework for climate and energy policies, the European Commission calls for a framework for the future development of environment and energy policy beyond 2020. However, much like the Energy Roadmap 2050 adopted by the Commission in December 2011, the Green Paper is based on scenario assumptions that are, to a great extent, not up-to-date. The European Commission would need to provide updated model calculations rapidly to enable energy policy decisions to be taken on the basis of transparent and comprehensible scenarios. A comparison of recent estimates conducted by DIW Berlin indicates that the Commission systematically underestimates the cost of nuclear power and carbon capture, transport, and storage (CCTS), while the cost of renewables tends to be overestimated. In particular this applies to photovoltaics where current capital costs are, to a certain extent, already lower than the Commission's estimates for 2050. In contrast to renewables, neither nuclear energy nor carbon capture, transport, and storage are cost efficient enough to play a central role in the future European electricity mix. It is therefore vital for Europe to continue to focus on the further development of renewables. This requires the setting of ambitious renewables targets for 2030 as well as clear emissions reduction and energy efficiency targets.

We present a mixed integer, multi-period, cost-minimising model for a carbon capture, transport and storage (CCTS) network in Europe. The model incorporates endogenous decisions about carbon capture, pipeline and storage investments. The capture, flow and injection quantities are based on given costs, certificate prices, storage capacities and point source emissions. The results indicate that CCTS can theoretically contribute to the decarbonisation of Europe’s energy and industrial sectors. This requires a CO2 certificate price rising to €55 per tCO2 in 2050, and sufficient CO2 storage capacity available for both on- and offshore sites. Yet CCTS deployment is highest in CO2-intensive industries where emissions cannot be avoided by fuel switching or alternative production processes. In all scenarios, the importance of the industrial sector as a first-mover to induce the deployment of CCTS is highlighted. By contrast, a decrease in available storage capacity or a more moderate increase in CO2 prices will significantly reduce the role of CCTS as a CO2 mitigation technology, especially in the energy sector. Furthermore, continued public resistance to onshore CO2 storage can only be overcome by constructing expensive offshore storage. Under this restriction, reaching the same levels of CCTS penetration would require a doubling of CO2 certificate prices.