THE EU'S PROPOSED CARBON BORDER ADJUSTMENT TAX (PART 2)

Cost Challenges Ahead Signal Inflationary Pressures

Last week we introduced our initial thoughts on the implications of a carbon border adjustment mechanism (CBAM) being proposed by the EU. To recap, the EU is looking to place a price on carbon for select imports into the EU to incentivize similar climate policies in the country of production. The EU also wants to revisit free carbon allowances that are currently used to protect EU domestic production of goods from relocating to other countries with less prohibitive policies.

Our first piece concluded that it is not obvious that a CBAM would be effective in reducing carbon leakage. Additionally, there is a real risk of continued trade flow deviations rather than decarbonization for sectors such as aluminum production in the EU. While aluminum imports may be more economically competitive than domestic production, the costs of a carbon tax are punitive for even low-carbon producers. A copy of the first piece may be found here for a complete recap.

This week we address our final two conclusions.

CO² prices may prove to be inflationary and could undermine energy transition policies in severe scenarios. Furthermore, technologies that many expect to deflate in cost (solar PV, for example) may re-inflate.

CO² prices are a form of subsidy. The IEA's recent roadmap for net-zero calls for a global CO² price of $130 per tonne by 2030 and $250 per tonne by 2050. Any technology that can decrease CO² is effectively subsidized. Companies with fewer emissions are also rewarded relative to peers. But CO² prices may not always drive decarbonization.

One of the challenges of CO² prices is that if a $100 per tonne CO² price is applied across the entire economy, and CO² emissions only fall by 20%, then the cost of CO² abatement is $500 per tonne, not $100 per tonne.[1] The abatement cost is simply the cost per unit of decarbonization technology minus the cost per unit of the incumbent technology, divided by the CO² reduction achieved from switching from the incumbent to the decarbonization technology. It is a helpful tool to compare different technologies in different industries.

On some level, this is an intuitive but essential observation: if the goal of CO² prices is to incentivize carbon reduction but fails to do so, then the C02 price is simply a consumption tax. Should CO² prices continue to increase with no effect on emissions, then the cost of removing (abating) emissions is very high. The CO² price only equals the cost of abatement if 100% of emissions are abated.

An active CBAM may have unintended feedback loops should it inflate the cost of new energy technologies.

Close to 90% of solar components heading into the EU are manufactured in China, which has a grid intensity close to 0.7 kg /kWh. It takes an average of 5MWh of energy to manufacture 1 kW of solar panels. This embodied carbon suggests that a $100 price would add ~$0.35/W to construction costs against an average baseline of $1.3/W, a ~30% increase.

CAPEX is the most significant driver of the levelized cost of energy for solar (measuring the total cost of ownership), at ~ 57%. This means that the cost of ownership increases by 17% should CAPEX increase by 30%.

This could be a problem for asset developers and the proliferation of renewable energy deployment. Encavis (ECV), the largest publicly traded European renewable asset developer, reported an operating return on assets of 7.2% for their solar projects in 2018.[2] Given these returns, a 17% increase in the total cost of ownership is problematic for developers.

The cost of solar has deflated a remarkable 90% over the last decade to ~4-7 cents per kWh. Technology improvements will undoubtedly continue to place downward pressure on that price, but future cost deflation may not be as extreme.[3] All else equal, an active CBAM would likely have inflationary consequences to solar panel imports coming into Europe.

Additionally, future deflation will be offset by rising curtailment levels as grids become more saturated with renewables. This, too, will start re-inflating the levelized cost of solar. When wind and solar supply ~40% of the generation to the grid, ~12% of new plant generation will fail to dispatch. The intermittency characteristics of renewables effectively overload the grid at certain times of the day if new capacity is added. This means that for each kW of capacity added, a smaller percentage of the potential kWh (energy) can be monetized. Less dispatch means less market revenue, driving up the levelized cost of energy under a steady cost profile. At a 40% penetration level, curtailment of renewables will raise levelized cost by about one (1) cent per kWh, or 25%. If renewables approach 60% of the grid's capacity, about 66% of renewable generation will fail to dispatch, raising levelized costs by ~ten (10) cents per kWh, a 250% increase.[4]

The recent IEA roadmap to net-zero has wind and solar providing 68% of power generation by 2050. To re-iterate, a significant portion of renewable power will need to be curtailed at that penetration level due to intermittency, which raises the required power price by ~200+% for developers looking to hold rates of return constant.[5]

Each $100 per tonne of CO² abatement cost inflates the CAPEX of solar by 30%, wind by 6%, and hydrogen by 5-10%[6]. If the cost of new energies inflates, then the costs of CO² abatement grows. It is not clear what the breaking mechanism is on this feedback loop. The energy transition makes it tough to raise interest rates as renewables are hit 4x harder than fossil fuel generation. Wind and solar today are generally financed with a meager cost of capital (~5%), so small increases in rates disproportionately impact renewable financing terms. Additionally, renewables are more capital intensive than other asset classes[7]. Depreciating upfront CAPEX absorbs 33% of renewables revenue, versus ~15% for average project/plant in different industries.[8]

None of the above is meant to detract from the importance of achieving carbon reduction in the global economy. We do, however, believe that costs matter, and many of the deflationary trends and forecasts for new energy technologies that are often required for accelerated adoption, may need revaluation. The implementation of a CBAM in the EU could have a meaningful price impact. Moving forward, investors should be mindful of the following considerations:

• In a scenario of lower imports, do European producers prioritize price or market share?

• Does a CBAM come with lower limits on free allocations or accelerate the removal of free allowances altogether?

• Where could imports fall, and what would be the cost position and utilization rates of domestic players in that local region?

• Is it possible to scale recycling infrastructure in the timeline commensurate with a rollout of carbon prices? Today, secondary supply accounts for ~25% of aluminum. What happens if that can be raised to 50%?

• Finally, EUA prices. The price of carbon in the EU ETS market, if used as a proxy for a CBAM price, will have a significant impact on eventual outcomes.

[1] If we have 100 tons of CO²emissions in the economy, 20 tonnes have been abated, and emitters of the remaining 80 tonnes are each paying $100 per tonne of additional costs this would yield: 80 tonnes * $100 / 20 tonnes abated =$500 per tonne.

[2] This is the last year ECV choose to publically disclose operating returns for this segment. A 7.2% return for 2018 is roughly their eight-year average which saw a peak of 9.8% and a trough of 5.9%.

[3] Some commentators call for 2 cents per kWh by 2050.

[4] Thunder Said Energy, June 2021

[5] Grid scale storage is most certainly an option to avoid curtailment. However, curtailment is often the least expensive option. Grid scale storage today with daily charging/discharging requires a 22 cents per kWh spread. Green hydrogen (used to back up intermittent renewables) is even more costly at 64 cents per kWh. It is not trivial to get around the second law of thermodynamics which states that any energy transferring process will come at an efficiency loss (10-20% for batteries, 50-60% for hydrogen.

[6] Thunder Said Energy, June 2021.

[7] As a proportion of total costs, capital costs make up a significant fraction as the marginal costs of production is often close to zero.

[8] Ibid.