Category: Investing in the Energy Transition

Proposed Clean Energy Credit Support for India

Exhibit: Facility to Raise Ratings; Facilitate Domestic Bond Issuance

Source: Council on Energy, Environment and Water, World Economic Forum

Key Points: A recently proposed credit-enhancement facility can help renewable energy projects access the Indian bond market — a nice example of a targeted financial mechanism to catalyze private investment. Its proponent, CEEW, believes the facility can have a 16x multiplier effect on the concessional capital and recycle bank capital for other energy projects.

Background: India’s Council on Energy, Environment and Water (CEEW), a think tank, and the World Economic Forum (WEF) engaged in a study to identify financing mechanisms and policy tools that could help foster more clean energy development in India. The team ultimately proposed ways to encourage more (debt) capital for (1) the development of utility-scale renewable energy (USRE) and (2) energy storage projects. This blog focuses on the proposed solution for USRE. It references the CEEW/WEF’s report and is informed by our recent webinar conversation with CEEW Director of the Centre for Energy Finance Gagan Sidhu (a replay of that conversation should be available in early December).

Indian banks appear tapped-out in terms of power sector credit exposure. The required investment in RE in order to reach stated RE capacity targets in India is more than double recent levels — ~$20-27 Billion (B) annually vs. $10B in the last few years. Thus, greater access to capital is required. Domestic financing for the Indian power sector is dominated by banks and non-banking financial companies. These sources appear to be near their limits in terms of credit exposure to the sector. As evidence, CEEW notes that the commercial bank credit exposure was roughly steady at ~$75B from 2015 through 2021 whereas bank credit to non-power sectors rose 40% over that period.

The domestic bond market is not (quite) open to Utility-Scale RE. India’s $450B domestic corporate bond market has seen some limited USRE activity. However, the overall market is limited in that issuances effectively require a AA rating to participate. USRE credits generally receive grades below that, a function at least in part of a somewhat checkered past in the sector that has included bank lending to fossil fuel-based power developers that lacked purchase commitments from an off-taker (one of India’ distribution companies) and contracts to secure access to fossil fuel inputs. However, USRE project debt ratings have been rising as a lower risk profile and supportive policies are recognized. CEEW catalogued that while no solar projects received an investment grade rating (BBB- or above) in 2012, by 2020 90% received one and 60% received an A or above. This progress is important, as it is expected to lower the cost of the credit support facility being proposed.

Proposed credit support facility. CEEW/WEF’s proposal is to create a facility that provides credit support for USRE projects. It would offer enough of a guarantee such that the projects receive a AA rating and thus can raise funds in the domestic bond market. In so doing, the facility would expand domestic capital access, both directly (as project developers use the bond markets) and indirectly (bond issuance can repay bank loans and thereby “recycle” constrained bank capital to be used in new projects). See Exhibit. CEEW/WEF believe the “multiplier,” i.e., the ability to raise commercial funds on the back of this concessional facility may be 16x, making it an effective tool in stimulating more private capital investment.

The proposed facility is now entering a phase in which stakeholders will consider how to “operationalize” it. CEEW/WEF note that factors influencing the facility include the type of capital used to fund the facility and the nature of the guarantee.

12/1/2022

South Africa’s Just Energy Transition Explainer

Exhibit 1: Proposed South Africa Energy Transition Spending

Sources: Government of South Africa; Blended Finance Taskforce and Centre for Sustainability Transitions at Stellenbosch University

Key Points: South Africa’s JET is an ambitious (easily >US$300 Billion required investment) plan to decarbonize and develop green industries. The economic potential highlights (1) the importance of government enabling and (2) that international grants (vs. loans) and government spending should focus where there is less financial return (like Just Transitions).

Just-released Just Energy Transition (JET) Investment Plan (IP) is for US$100 Billion through 2027. A year after the announcement of an international partnership dedicated to a comprehensive “greening” of South Africa, with financial commitments from its international partners, the government of South Africa last week released its JET Investment Plan in time for COP27. This plan, which covers the five years through 2027, is comprised roughly of $60 Billion (B) for electricity transformation, ~$35B for green industry development — Electric Vehicles (EVs), Green H2 and the municipal infrastructure to support EVs — and the balance for Just Transition, predominantly for the province of Mpumalanga, which is heavily dependent on coal (see Exhibit 1).

Total spending through 2050 could easily exceed $300B. What has been released is a “phase 1,” although the IP lays groundwork for further investments and green economic growth over the next ~25 years. (The plan does detail spending expectations in the electricity sector through 2035, by which point it expects power-related expenditure to have been US$150B vs. the aforementioned $60B by 2027.) For perspective, an independent estimate of total spending for just the power decarbonization portion is US$250B (see Exhibit 1). Coupled with subsequent spending to support the EV and Green H2 industries, it suggests that total investment in these areas can well exceed US$300B by 2050.

Coal retirement schedule in the IP accelerates after 2030. The JET IP envisions a retirement/decommissioning schedule for the country’s coal capacity of 39GW as follows: 5GW by the end of 2029, 9.5GW (cumulatively) by the end of 2030, 22GW (cumulatively) by 2035 and all but the two youngest plants in the country by the end of 2050. The retirements accelerate after replacement (primarily green) energy has been put in place.

Government action creates private sector power opportunity and penalizes carbon. Through the course of 2022, the South African government has taken steps to liberalize the electricity market in country as well as to implement specific climate policy. Some highlights:

• a climate change bill for the transition and for investment in climate resilience is working its way through Parliament
• a climate tax was introduced by the Ministry of Finance
• changes in electricity sector regulation, including establishing an independent transmission operator
• liberalization of generation: more latitude for independent power producers, for example by raising the licensing threshold for new capacity to 100MW from 1MW

The IP envisions a blended finance model. The IP details commitments that have been made from international and domestic entities as follows below. Assuming that all of the indicated commitments come through, it leaves US$47B to be secured of the $100B planned investment (see Exhibit 2).

• The international partners in South Africa’s Just Energy Transition Partnership, the governments of France, Germany, UK, USA and the EU, have committed US$8.5 of financing for the period 2023-2027. That support is going largely to electricity infrastructure, with modest amounts also going to planning/implementation capacity, EV and Green H2 infrastructure and Just Transition. Referred to as the International Partners Group (IPG) in Exhibit 2.
• Development Finance Institutions/Multilateral Development Banks (DFIs/MDBs in Exhibit 2), including the New Development Bank and the International Development Corporation, have committed US$10B.
• Several private institutions in South Africa have made public commitments to fund climate finance assets totaling ~US $33B.

The IP also details the nature of (logical) participation by activity, i.e. whether government, concessional, private/commercial (including Venture Capital) and/or grant sources. As envisioned, concessional and government sources play actives role in decommissioning and repurposing the coal plants, building infrastructure and capabilities across industries and Just Transition efforts in Mpumalanga.

Exhibit 2: Estimated Composition of Financing Sources, by Target, 2023e-2027e (in South African Rand Billions)

Source: Government of South Africa JET IP

This process is being watched by several countries. Countries including Indonesia, Vietnam, India and Senegal are engaging in conversations with international partners regarding their own versions of JET. These are bespoke and the intent is to design them around conditions specific to each. Yet they all embrace the economic development/industrial policy goals embedded in South Africa’s JET.

11/7/2022

A CCS Network Gets Its First Project

EnLink Natural Gas Mississippi River Pipeline Network and Facilities’ CO2 Emissions

Source: EnLink Midstream LLC

Key Points: The CF Industries/EnLink/ExxonMobil announcements earlier this month marks the EnLink network’s first firm CCS commitment and positions ExxonMobil to take CO₂ from others in the region. The network is premised on better CCS economics from high-concentration sources, scale and retrofitting existing pipelines. IRA tax credits are a key enabler.

CF Industries/EnLink/ExxonMobil project to store 2 Million tonnes per year of CO₂. Earlier this month CF signed an offtake agreement with ExxonMobil (XOM) for CO₂ to be recovered at CF’s Donaldsonville, LA facility starting in 2025. The CO₂ is to be taken along EnLink Midstream’s (ENLC) pipeline network to XOM-owned acreage (125,000 acres) in Vermilion Parish, LA where XOM will sequester it underground. With the CO₂ capture, CF claims it will be first to market with up to 1.7 Million tonnes per year (mmtpy) of blue ammonia.

Broader agreement between XOM and ENLC for Carbon Capture and Storage (CCS) projects. Along with this announcement, XOM and ENLC entered into a Transportation Service Agreement. ENLC will deliver up to 3.2 mmtpy initially (beginning in 2025) and eventually up to 10 mmtpy of CO₂ from the Mississippi River corridor to XOM’s Vermilion Parish acreage, using ENLC’s pipeline network (after retrofitting from current hydrocarbon service). The agreement seeks to leverage highly-concentrated sources of CO₂ that can be more readily captured and then transported to a sequestration location — ENLC has noted that the Mississippi River corridor emits 80 mmtpy and has one of the highest concentrations of industrial CO₂ emissions in the U.S. (see Exhibit). The company also cites 4,000 miles of existing pipeline in LA that can be used for CO₂ transport.

This deal is just one part of XOM’s many CCS efforts. XOM has taken a leading role in various CCS initiatives globally, including in the formation of the Houston Ship Channel consortium, which now has 14 companies and seeks to store 50 Million tonnes of CO₂ by 2030. We note that the ENLC deal comes as there is speculation that XOM is in talks to acquire Denbury Resources, which in addition to its hydrocarbon assets owns the largest dedicated CO2 pipeline network in the U.S., at ~1,300 miles spread across the Gulf Coast and Rockies.

ENLC has moved to bring others into the Mississippi River network. ENLC formed similar transportation agreements earlier in 2022 with Talos (Memorandum of Understanding signed in February) and Oxy Low Carbon Ventures (Letter of Intent signed in May) to transport CO₂ to both companies’ acreage in LA. There have been no customer/off-take announcements for Talos or Oxy. ENLC also agreed with Honeywell to jointly market Honeywell’s CO₂ capture technology offerings.

10/27/2022

A Creative Approach to Tackling Foreign Exchange Risk

Exhibit 1: Clean Energy Project Funds Flows with Exchange Rate Coverage Facility

Source: Columbia Center on Global Energy Policy

Key Points: A newly-suggested Exchange Rate Coverage Facility integrates carbon credits, multilateral bank guarantees and long-horizon commercial and philanthropic capital to lessen the expense of protecting against local currency depreciation. Some version of this blended facility concept can plausibly help stimulate more international investment into clean energy.

Proposing the ERCF. A team from Columbia University’s Center on Global Energy Policy and the World Economic Forum earlier this month released a discussion of a proposed Exchange Rate Coverage Facility. The ERCF is designed to lower, or potentially eliminate, the cost of hedging foreign exchange rate (FX) risk for clean energy development in emerging economies by creating insurance to be paid directly to the foreign (currency) lenders (see Exhibit 1). By mitigating FX risk, a key challenge for international investors and lenders, it is hoped more capital can be directed to clean energy development.

The authors offer that the ERCF may potentially be used in conjunction with, and therefore its structure (described below) may be adjusted to fit around, existing hedging mechanisms. In other words, a version of the ERCF might be applied when existing commercial hedging is too expensive or unavailable (e.g. for some % range of devaluation for a given currency). Separately, the authors note that the product is likely financially more attractive for participants as a portfolio of projects across countries, which diversifies away exposure to any one currency.

Envisioning a ladder of funding support. The intention of the mechanism is to fully hedge/insure against local currency depreciation. The energy projects the ERCF seeks to support generate revenues in local currency (selling power to local customers) while their debt service obligations are in a foreign currency. As the local currency devalues, payments to be made in the foreign currency get more expensive, putting economic stress on the project owner.

The authors propose a ladder of coverage, with different sources of support “covering” the full range of potential local currency depreciation (see below and Exhibit 2).

Exhibit 2: The “Ladder” of Coverage for Local Currency Depreciation in the ERCF

Source: Columbia Center on Global Energy Policy, Payne Institute

Carbon credits are proposed to provide the first and last coverage. As proposed, the first 20% of a local currency’s depreciation relative to an agreed reference rate (i.e. a decline to 80-99% of its reference value) and the last 20% (i.e. a decline to 0-20% of its reference value) would be covered by revenues generated from carbon credits. As envisioned, the credits would be issued under the auspices of Multilateral Development Bank (MDB) programs such as the World Bank’s Carbon Initiative for Development, which could provide a guaranteed price floor and purchase agreements. The credits could be a portion of total carbon offset credits generated for the project. When monetized, they can be banked for potential future use.

In between, a combination of guarantees and institutional/philanthropic capital. The proposal includes three types of coverage for the devaluation range in between what is covered by carbon credits. The presumption is that the providers of capital for these slices would be remunerated in some form for providing guarantees.

• If the currency declines in the range of 20% to 35% versus its reference value, it would fall to MDBs to cover this “slice” of the value decline; the host country, however, would have to provide a counter-guarantee, thus exposing the country/government to this degree.
• For currency value declines of more than 35% and up to 50%, MDBs would again guarantee financial support — for this slice, however, there would be no host government guarantee.
• For currency devaluation of more than 50% and up to 80%, financial support would come from private capital, which is presumed to include some philanthropic capital.

  10/12/2022

Cost of Capital Observatory Launch Shows There Is Much Work To Do

Cost of Capital Survey Weighted Average Cost of Capital vs. Country Bond Yields

Sources: IEA/WEF, World Government Bonds

Key Points: Last week’s launch of IEA/WEF’s Cost of Capital Observatory starts to delineate investors’ views of the risks of energy investment in emerging economies. Initial results show underdeveloped risk assessment, which supports why investment is lacking. Also, a weak relationship between country bond yields and WACC suggest other drivers are also relevant.

Goal of the Cost of Capital Observatory (CoCO). The International Energy Agency (IEA), The World Economic Forum (WEF), ETH Zurich and Imperial College London have introduced the CoCO — an initiative to lower emerging markets’ cost of capital by bringing transparency to real and perceived risks of clean energy investing in specific countries. It is hoped that greater transparency, along with policy or mechanisms to address key risks, can lower investors’ return requirements and spur more investors to put money to work.

1,000 basis point spread in WACC illustrates how poorly risks are understood. The launch last week included publication of results from a survey conducted earlier this year. The survey solicited feedback from financial actors about the cost of capital and related inputs for two project types (one new solar facility and one natural gas facility) across five countries (Brazil, India, Indonesia, Mexico and South Africa). Illustrating the challenges of accessing funding currently, the surveys yielded Weighted Average Cost of Capital (WACC) spreads of as much as 1,000 basis points (i.e. 10%) for a given project in a given country.

Cost of capital 2-3x higher in emerging economies than “advanced” economies. The relative paucity of respondents and the aforementioned dispersion makes assessing results somewhat challenging, but median required WACCs in the survey responses for solar projects ranged from just under 10% (for India and Mexico) to 13% (for Brazil) (see Exhibit). This range suggests 2-3x more expensive financing than in the OECD. Further, the implication is that financing costs in these countries account for ~1/2 of total levelized costs of a solar PV plant vs. ~25-30% in the OECD and China.

Many of the perceived risks relate to the country, but go beyond country risk. The survey results include only contractually-supported revenue streams (like Power Purchase Agreements or PPAs), thus removing merchant risk from the evaluation. Further, the IEA indicates that respondents’ WACC for solar projects were equal or a bit below for natural gas. At the risk of over-reading relatively few results, we observe a only weak relationship with country bond yields; or to put it differently, survey respondents’ WACC requirements seem much less sensitive to bond yields for South Africa and Mexico and/or more sensitive for Brazil (see Exhibit). We imagine this weak relationship is due to the variety of risks including regulatory, political, off-taker (which is often a government-backed utility), currency and land acquisition (concerns about permitting and land rights).

Ideally, the CoC progresses with more granular perceptions of risk drivers. In its goal of transparency, the IEA et al is seeking more detailed insights into the impact of these various risks on WACC requirements. The effort may meet some resistance from the investment community, as some investors are likely to view their proprietary risk analysis to be a strategic advantage. Yet, it is hoped that the launch raises awareness of the initiative, which furthers efforts to get insights and responses.

9/28/2022

Factoring Unknowns into Carbon Dioxide Removal Investment

Exhibit: Verification Confidence Levels and Frontier’s View on Investment

Source: Frontier and CarbonPlan

Key Points: CarbonPlan has calibrated uncertainties in measuring how much carbon is removed by various technologies. This is feeding Frontier’s decision process — and should add confidence for other buyers/investors to step in — to support emerging Carbon Dioxide Removal companies. It also gives CDR companies incentive to invest to minimize these uncertainties.

An effort to bring rigor to assessing uncertainty in verifying carbon removal. CarbonPlan’s quantification exercise establishes Carbon Dioxide Removal (CDR) technology “verification confidence levels” (VCLs), i.e. how much uncertainty there is across various factors in net permanent removal of carbon (net = after factoring in the emissions associated with the materials or the energy it takes to implement the CDR operation).

VCLs part of the invest/do not invest decision for Frontier. Frontier is to use these Verification Confidence Levels as a factor in deciding if to invest and how much to discount for uncertainty. A low VCL dictates that the technology isn’t ready for larger purchase commitments from Frontier (offtake commitments); Frontier may (only) be willing to support the development of the technology through more modest “pre-purchases” or it may determine that in fact the technology isn’t ready for its funds at all, but rather should (continue to) be funded through research grants (see Exhibit).

For more on Frontier’s investment business model and its focus on nurturing CDR technologies with the potential to massively scale, please see a previous Payne Financial Flow that discussed its inception and fundraise.

 A larger discount (and thus cost) to “claimed” results based on a lower VCL. Frontier’s discounting mechanism applies a specific uncertainty estimate (each VCL encompasses a range) to the claimed amounts of tons removed. In its illustration, Frontier suggests that Direct Air Capture (DAC) has a 5% uncertainty discount (it is VCL 5) whereas Enhanced Rock Weathering is given a 34% uncertainty discount (VCL 2). Thus if a DAC project claims it can remove 100 tons, Frontier would assess the project’s delivered tons as 100 * (1-0.05) = 95 tons. Similarly, if the project claims $800/ton of removal, Frontier’s calculated cost would be $800 / (1-.05) = $842/ton.

Frontier is quick to point out that a lower VCL does not preclude investment. Technologies with (or that Frontier believes can scale to) large removal potential but still higher uncertainty levels may make sense. But a more rigorous quantification of the uncertainty allows Frontier to make that determination. Separately, Frontier is signaling the benefit for CDR companies of reducing uncertainty — in that greater uncertainty raises the effective cost of the technology vs. other candidates for investment. And it is indicating an interest in investees’ commitments/initiatives to reduce uncertainties, for example in new sensing tools tied to the specific CDR technology.

VCLs set by each characteristic of six removal technologies. CarbonPlan evaluated the VCLs for six CDR technologies: Direct Air Capture, Biomass Carbon Removal and Storage, Enhanced Weathering, Terrestrial Biomass Sinking, Ocean Biomass Sinking (with and without Harvest) and Ocean Alkalinity Enhancement (Electrochemical and Mineral). For each technology, the uncertainty is assessed for each factor related to the effectiveness and durability of removal (as well as the emissions associated with the materials or energy required to have it function). Ranges are used, which reflect degrees of uncertainty (about the uncertainty).

9/21/2022

Two Insurance Innovations for Energy Transition

Exhibit: Marsh’s Insurance Services Through H2 Project Construction

Source: Marsh

Key Points: Insurers have introduced two products over the last month that can help support private investment in the Energy Transition. Marsh is to cover construction-through-first-year-operations for green and blue H₂ projects. Howden is to cover invalidation risk for voluntary carbon offsets.

Marsh’s H₂ insurance covers through the early stages of H₂ production. In late August Marsh, working with Liberty Mutual and AIG, began offering up to $300 Million cover for construction-through-first-year-operation of green and blue hydrogen production projects. (The “color” of hydrogen denotes its source; green refers to H₂ made using renewable energy via electrolysis while blue refers to H₂ produced from fossil fuel with the emitted carbon then captured and sequestered to mitigate the environmental impact.) The insurance provides cover for property damage risks, marine cargo, business interruption costs, general third party liability, and contingent delay-in-start up.

Marsh et al avers to be the first provider of this insurance coverage. Reports from other insurers point to ongoing work to develop products and address the risks that are unique to H₂ related to increased flammability, embrittlement of steel/blistering of carbon fibers and risk of leakage. For underground storage of H₂, small molecule size makes it more mobile than methane or CO2 and thus applicable cavities may be limited to salt caverns and some aquifers or depleted hydrocarbon fields. These issues would appear to make it more challenging for the insurance industry to provide ongoing/operational coverage.

Howden introduces insurance for voluntary offsets. In early September, Howden Group introduced carbon credit invalidation insurance for the voluntary carbon market (VCM). The insurance is to cover third party negligence and fraud against credits that are deemed to be “high quality” and have had independent verification. It is intended to give buyers an extra measure of confidence in the value and validity of their carbon offset purchases. The insurance initially covers a specific portfolio of projects that have been (further) verified by carbon finance firm Respira International; the related offsets are being sold as a combined lot to diversify the risk. If fraud or negligence is discovered after the offsets have been sold, Respira can make a claim on the insurance and compensate the buyer.

The voluntary cover is modeled on related company’s compliance offset product for the California markets. Howden-sponsored insurer Parhelion, which served as an adviser in development of this VCM insurance, offers invalidation insurance for offsets used as part of California’s cap-and-trade market and this may provide some additional insight on the terms of the VCM cover. Terms of the cap-and-trade offset product include: coverage for three years after issuance, for errors that result in overstating the greenhouse gas (GHG) benefit by more than 5%, for non-compliance with applicable regulations and for any double-issuance (i.e. an offset issued for the same project/boundary in another offset market).

For more detail on the role of offsets in this California cap-and-trade program, please see our recent Payne Financial Flow post.

9/16/2022

Enviro Strength Within Soft 1H22 ESG Bond Issuance

Exhibit: Total ESG Bonds Issuance by Type, US$B, 1Q21 – 2Q22

Source: Environmental Finance

Key Points: Headlines noting large declines in ESG bond issuance in 1H22 vs. 1H21 obscure that environmentally-targeted issuance was resilient. Total ESG bond issuance in 1H22 fell 22% yr./yr. vs. a 13% decline for all bonds, but Green bonds + Sustainability-Linked bonds (2/3 of which have carbon emissions targets) fell only 6%, helped by 2Q22’s sequential bounce.

ESG bond issuance in 1H22 declines 22% yr./yr. to $441B on large declines in Social and Sustainability bonds. According to the Environmental Finance (E-F) database, Social bond issuance fell by 45% yr./yr. in 1H22 to US$81 Billion (B), Sustainability (defined as a combination of Green and Social activities) issuance fell 31% to $74B, Green issuance fell 10% to $239B and Sustainability-Linked issuance rose 22% to $46B (see Exhibit; some numbers may not match due to rounding).

Total ESG bond issuance in 1Q22 of $192B marked a low point vs. any quarter in 2021; 2Q22’s total of $249B reflected recovery in every sector except Sustainability-Linked.

Social bonds appear to have normalized following a Covid-19-driven spike in 1Q21 that had been driven largely from Supranational organizations. Supranational issuance declined 53% yr./yr. in 1H22 to $55B, followed by (government) agency issuance down 26% to $70B and Corporate issuance down 18% to $158B.

And Sustainability-Linked bond (SLB) issuance was just beginning to accelerate in 1Q21, making for an easier comparison for 1H22. Growth in SLBs in 2022 has also included sovereign issuance and some “relaxation” of the Key Performance Indicator (KPIs or targets) requirements.

Note, we are unsure the degree to which currency exchange rates affect reporting (e.g. we are unsure how much issuance is done in local currencies). To illustrate, Europe has dominated ESG bond issuance (was 46% of issuance in 1H22). The US Dollar (USD) vs. the Euro is 9% stronger thus far in 2022 than in 2021 and so currency translation into the stronger USD in 2022 lowers USD-stated values (i.e. further support the idea that there has been resiliency).

Data available upon request.

7/21/2022

Methane Abatement’s Underfunding Problem

Exhibit 1: Sector Investment vs. GHG Emission Mitigation Potential

Source: Climate Policy Initiative (with input from Intergovernmental Panel on Climate Change)
Exhibit 2: % of Methane Abatement Finance vs. Methane Emissions by Sector

Source: Climate Policy Initiative (with input from the Community Emissions Data System)

Key Points: A CPI study highlights severe underfunding of methane abatement efforts ($11.6B vs. a required $110B per year) relative to methane’s impact on global warming (and commercial potential, at least in Oil & Gas). It calls on government to provide policy for methane emissions reduction and reporting and more fiscal incentives for private investment.  

Spending 1/10^th of what is required for methane abatement. A study out this week by the Climate Policy Initiative on Methane Abatement Finance concludes that global spending of $11.6 Billion per year was spent on average in 2019 and 2020, approximately 10% of the total required for methane abatement to play its role in keeping global warming under 2ºC by 2050. Put differently, it cites that methane abatement spending comprised 2% of climate finance while it argues that methane emissions are responsible for almost ½ of global warming.

Significantly less spend per ton of CO₂e abatement potential than other GHG abatement efforts. The study puts the underspend in context of other GHG emissions abatement efforts, using a ratio of investment flows ($B) to annual mitigation potential by 2030 (in Gigatons of CO₂ equivalent). There was 12 times less $B/GtCO₂e per year spent on methane abatement than in low carbon transport — a ratio of 3.9 $B/GtCO₂e ($11.6B spend/3.0 GtCO₂e per year mitigation potential) for methane abatement vs. 45.6 for low carbon transport (see Exhibit 1).

Within methane abatement spending, disproportionately less spending in the Oil & Gas sector. The study cites a mismatch between source of methane emissions and funding going to try to abate it. The waste and water sector accounts for 62% of tracked methane abatement finance but only 18% of methane emissions. On the other hand, the fossil fuel sector accounts for 1% of tracked spending but 41% of methane emissions (see Exhibit 2). With that said, the study acknowledges the very high likelihood of under-reporting of investment by fossil fuel companies and agriculture, forestry and land use (AFOLU) (as well as under-reporting of methane emissions).

Regulation and incentives to spur investment in fossil fuel methane abatement. The study acknowledges the significant momentum building within the fossil fuel sector towards methane abatement. This includes new commitments and regulations in OECD countries as well as voluntary steps by the sector, such as those adopted by signatories to the Oil & Gas Climate Initiative. Although it is often cited that capturing methane lost to leakage can pay for itself, the study correctly notes that incentives can be misaligned, either because the natural gas infrastructure isn’t in place or the owner of the equipment may not benefit directly from reducing leaks. Thus, it recommends a combination of additional regulation and incentives. The potential incentives cited include use of carbon offset credits; only 13% of the credits issued between 2015 and 2020 related to methane abatement, per the Berkeley Carbon Trading Project’s Voluntary Registry Offsets Database.

7/15/2022

DAC’s Development Stages

U.S. DoE Standard and Accelerated Timelines In Its Regional DAC Hubs Program

Source: U.S. Department of Energy

Key Points: Announcements at the end of June highlight the varying technological readiness levels of Direct Air Capture (DAC). Frontier is supporting a diversity of nascent technologies, while Climeworks’ scaling effort is now underway. Meanwhile the U.S. DoE and Climeworks offer hints at potential “learning curve” benefits for capex over the next decade+.

Early stage DAC investments. Formed in April 2022, the Stripe-led Frontier fund raised $925 Million (MM) to be to Direct Air Capture (DAC). Frontier announced at the end of June that it is making early stage investments totaling $2.4MM in six DAC technology companies. Its investments are to take the form of Advanced Market Commitments (AMCs), i.e. it is committing to buy (initial) carbon removal from the companies; Frontier indicated it is paying $500 to $1,800 per ton of removal with this commitment (thus it is targeting to capture an implied +/-2,000 tons). Further, Frontier is offering $5.4MM in contingent payments to the six upon completion of certain milestones. Separately, Clean Energy Ventures announced a $3MM seed commitment to one of the six companies (Travertine), bringing announced potential funding to just under $11MM. In other words, the vast majority of the raised funds are to be spent, still through AMCs, only down the road to scale up construction of removal technologies once they have been validated.

Frontier’s DAC investments span several technologies. Frontier noted an encouraging diversity of prospective DAC technologies across 26 applications for funding. New technologies for the six selected companies include (1) new adsorbents for DAC systems (e.g.s include a AspiraDAC’s Metal-Organic Framework and Calcite-Origen’s slaked lime for calcination); (2) enhanced weathering techniques (e.g.s include Lithos’ basalt application to cropland and Travertine’s use of electrochemistry to produce sulfuric acid); and (3) synthetic biology (e.g. Living Carbon’s algae biopolymer).

Meanwhile also late last month, Climeworks breaks ground on a significant scaling up. The Frontier fundraise was the largest chunk of nearly $2B in carbon removal fund raises in April. Yet the second largest chunk, a $650MM raise for Climeworks, allows it to scale its existing technology. Related to the fundraise, Climeworks has broken ground on its Mammoth plant with capacity of 36,000 tons per year (tpy); intended startup is within 24 months. This follows the start up in September of last year of the company’s 4,000 tpy Orca plant.

U.S. Department of Energy initiated its $3.5 Billion Regional DAC Hubs program in May 2022. Funded under the Bipartisan Infrastructure Law, the program is authorized to spend the funds through 2026 to contribute to the development of four hubs with the capacity to capture (and sequester and/or utilize) at least 1MM tons each of CO₂ per year. Costs are to be shared with the private sector, with the DoE picking up 80% in Phase 1 (feasibility) and 50% in Phases 2 and 3 (FEED through start of operation) (see Exhibit).

A vision to scale capex economies after 2030. Perhaps offering perspective relative to the implied cost of the DoE initiative, Climeworks, at its Direct Air Capture Summit at the end of June, estimated a need for $30-50B per year of capex, as well as customer (corporate) support in the form of long term offtake contracts, in order for the DAC industry to reach gigaton (i.e. one billion tons) annual scale capture by 2050. Acknowledging the math is very rough, if the DoE initiative points to capex of at least $1,750 per tpy of CO₂ for the regional hubs ($7B+ divided by 4MM tpy), the Climeworks capex estimate suggests a learning curve benefit (after 2030) to potentially as low as $600 per tpy.

7/7/2022