Recent events have brought a repricing of risk across the global economy and to the energy sector in particular. Energy investments face new risks from both a funding – i.e. how well project revenues and earnings can support new expeditures on corporate balance sheets – as well as a financing perspective – i.e. how well debt and equity can be raised to supplement corporate and government funds.

These are most apparent from the estimated declines in revenues facing both the oil and gas and power sector in 2020, as well as equipment and goods suppliers (see Overview), exacerbated by financial market volatility and a slowdown in project finance transactions and mergers and acquisitions. The cost of money has risen for most actors save for mature market sovereigns, whose bond yields have fallen. The ability to price and structure financial deals remains challenging due to strong market volatility as well as the physical situation of industry professionals. Near-term liquidity constraints and growing risk of defaults across the economy also cast uncertainty, with many companies and investors opting for capital discipline over financing new transactions.

There are questions over how short-term market volatility will affect the industry landscape and investment decisions. Like the wider economy, the financial conditions for energy-related companies have changed in 2020, in particular with top companies experiencing falls in market capitalisation steeper than those of equity benchmarks. While falling share prices more directly impact investors, they provide a signal of expectations for profitability and increase the cost of issuing equity.

In the near-term, the challenges concern liquidity – sufficient cash flow to keep businesses operating and meeting obligations with customers and suppliers. Shifting market fundamentals and uncertainty over the timing and nature of economic recovery is also pressuring profitability, which shapes future funding capacity. Coming into 2020, indicators for energy-related industries trailed market benchmarks in these areas. Early observations suggest higher risks around certain segments.

Over the past two years, the market capitalisation of the top-listed oil and gas companies declined by nearly 50%, with most of the fall coming in the past year, as investors reassessed risks and profitability expectations in the face of lower oil prices, emerging oversupply and uncertainty over how well companies can position themselves in a changing market environment. These risks are also reflected in an increase of volatility compared with the wider market, as expressed by a higher beta, which was rising even before the recent crisis took hold.

For some segments, such as US shale producers, which rely on debt markets to finance operations, the knock-on effects from much lower oil prices have resulted in much higher borrowing costs and near-term liquidity constraints for a number of companies. For better capitalised players (e.g. the Majors) financial developments have forced companies to cut capital spending; dramatically re‑evaluate investment plans, and in some cases dividends; and look to debt markets to help fund shareholder commitments (see “Sectoral trends” section below).

The financial situation is varied for the power sector, where the top-listed companies have seen a loss in market capitalisation of only around 5%. Some buffer is provided by the more predictable revenues for utilities from regulated networks and renewables, where investments are increasingly focused, while many power producers in competitive markets have hedged some merchant exposure a year ahead (Rack, 2020). Renewable developers also came into 2020 with improving performance. 

That said, declines in power demand, uncertainties over future pricing for wholesale market generators and exposure to gas distribution as part of utility business models raise new funding challenges. Borrowing costs have also risen and utilities face credit risks from non‑payment by customers under financial stress. For European utilities that had already seen earnings erode over the past decade in the face of lower demand, the financial picture is more shaky, while US utilities entered the crisis on firmer footing. Some state-owned utilities in emerging economies that borrowed heavily in foreign currency now face ballooning debt obligations, with potentially less relief available from government coffers. Given long capital cycles for power, shifting financial conditions appear to have less of an impact on current capital spending compared with oil and gas (see Power Sector section), but the financial risks vary considerably by market and segment.

Players in the electrical equipment supply chain – which helps to provide everything from turbines to grid components to energy management systems – may face more challenging financial conditions than project developers. With economic uncertainties, some governments and utilities are delaying procurement of power projects, which means reduced order books and cash flow for suppliers, though there may be an opportunity to focus on repowering existing assets and adopting more flexible payment terms. Consolidation pressure on smaller renewables manufacturers with weaker balance sheets may accelerate, while larger players may be able to weather the storm with cost cutting.

Finally, automakers also face a much more uncertain financial picture with a steep fall-off in sales in the first months of the year and a more than 30% loss in market capitalisation, second to that of oil and gas. This raises questions over the turnover of the vehicle fleet as well as the continued roll-out of more efficient vehicles and EVs, particularly in the face of much lower fuel prices (see Energy End Use and Efficiency section).

The financial markets can play an amplification role for energy investment on both the downside and the upside. While uncertainties abound in the near term, conditions may be ripe for refinancing and acquisitions that can help lower the cost of finance and improve the confidence of developers to invest, knowing that they can quickly recover their capital. Such opportunities have increased in recent years and could now become more attractive for institutional investors searching for yield with risk appetite for assets, such as renewables, energy infrastructure and other capital-intensive technologies with reliable revenue profiles. They may also be reinforced by some of the longer-term preferences expressed in the market for allocating capital towards sustainable finance opportunities. Further discussion of these dynamics are found in the sections below on the “Role of institutional investors in energy investment” and “Sustainable finance and energy investment”.

Private decisions to invest will of course also depend on the evolution of the current crisis and actions taken by governments to support markets. For example, while investors have increased their focus on sustainable finance in recent years, there are questions over the clarity of energy policy signals and alignment of financial policies that would better channel financial flows to real sustainable assets. Moreover, in markets and sectors where investment risks remain relatively high, the risk-taking capacity of public finance institutions may play an increasingly important role.

Despite growing cost-competitiveness, which has supported rising deployment for solar PV and wind over the past decade, renewables investments are not expanding at the rate needed to align with sustainability goals. They would need to more than double over the next decade. That said, decisions to allocate capital towards different mixes of fuels and technologies depend a lot on financial performance, taking into account not just returns, but the level of risk as well.

The IEA and Imperial College London are investigating the risk and return proposition available to investors in the energy sector through a series of special reports. The first study focuses on historical financial performance of fossil fuels versus renewable power in listed equity markets of select advanced economies.We constructed hypothetical investment portfolios to compare fossil fuel and renewable power business segments in three geographies: the United States, the United Kingdom, and Germany and France. The methodology described in the report will be extended to other countries and unlisted (i.e. private market) investments in forthcoming work.

The findings indicate that renewables shares in these markets over the past decade offered higher total returns relative to fossil fuels, with lower annualized volatility (a measure of investment risk). Over January-April 2020 renewable power companies held up better than fossil fuel companies during a period of severe stress and volatility.

So why has the apparent financial attractiveness of renewable power in equity markets not resulted in a more pronounced reallocation of investor capital? One reason is that the characteristics of a dedicated renewable power portfolio are substantially different from those of pure play fossil fuel portfolio. These characteristics (such as average market capitalization, dividend pay-out ratio, firm capital structure, and liquidity) matter a lot to large institutional investors.. Additional measures, and development, may be required to prepare the industry for fully-fledged support from listed equity markets. How quickly this occurs, and whether existing norms in the investment industry will adapt to the funding needs of a relatively new asset class, are key questions for further study.

The share of private-led energy investment, in terms of ownership, has increased since 2015. There has been a growing role for renewables, where private entities own nearly three-quarters of investments; energy efficiency, which is dominated by private spending; and private-led spending in grids and battery storage. But state-led investments have remained relatively robust in certain sectors, such as oil and gas and fossil fuel-based generation. Overall, the SOE share of energy investment was 36% in 2019, down from nearly 40% in 2015.

SOEs account for nearly 40% of power investments, though this share has fallen since 2015, from lower spend by Chinese SOEs in coal-fired generation and networks. In some emerging markets outside China, the role of SOEs in power investment increased, with more resilient investment in fossil fuel generation by SOEs, compared with private actors, notably coal plants in India and South Africa and gas plants in North Africa. SOE investment in coal plants in Poland also increased.

Electricity sector investment by the private sector and consumers declined less than that of SOEs over 2015‑19, mainly due to more resilient investment in renewables and a higher share of grid spending in markets with investor-owned utilities. This was reinforced by a rise in distributed solar PV and an increase in consumer spending on energy efficiency, helping to boost the total private share. Notably, in emerging economies, private actors play a predominant role in renewables investment (except hydropower, where state players dominate), but their projects typically sell to state-owned utilities.

In upstream oil and gas, the share of NOCs in investment remained over 40% in 2019, though spending in the Middle East and Russia, where NOCs dominate, increased less than in other parts of the world, notably in the United States and in shale, where private companies are more important. This share is still higher than before the oil price collapse in 2014 as large private oil and gas companies, including the major oil companies, cut back spending more heavily in 2015 and 2016, a trend likely to be reinforced with the downturn in 2020.

Given an expected downturn for global energy investment in 2020, additional questions are emerging over how the role of NOCs and SOEs will evolve. Private actors, at least in oil and gas, have borne the brunt of capital cuts thus far, and SOEs may also be a vehicle for some governments to carry out fiscal stimulus measures. Still, some indebted and poorly performing NOCs are also being hit very hard by the current crisis, with knock-on effects on host governments that rely on oil and gas revenue to provide essential services (see Fuel Supply section).

In 2020, a repricing of country risks in some developing economies led to rising government bond yields and falling currencies. SOE financing is often tied to the sovereign entity guaranteeing the debt, and so sharp declines in emerging market bond prices means rising financing costs. South Africa has lost its last investment grade rating on its credit. Compounding the situation, a number of SOEs (e.g. Eskom, Pemex, PLN, Petrobras) have borrowed heavily in foreign currency and now face debt repayments some 15-30% higher in domestic currency terms, alongside more uncertain revenues from changing market conditions.

In the near term, governments may find themselves stepping in to shore up SOE finances, particularly through providing liquidity, refinancing and foreign exchange reserves to meet growing debt challenges. But reduced fiscal capacity and higher borrowing costs from the crisis may also hamper their ability to respond.

Companies across the oil and gas sector now face an unprecedented stress test – in their business strategies, operations and financial models – from a sharp demand shortfall from the current economic crisis and a supply overhang (see Fuel Supply section). The sector as a whole faces the prospect of a smaller and more competitive space within which to operate, though the financial implications and strategies vary strongly by type of company. Here we discuss the choices faced by oil and gas Majors in balancing investment priorities with new financial pressures – to weather the current downturn and position future energy portfolios. The situation of US Independents is also treated below.

By the end of 2019, Majors had greatly improved financial performance relative to the previous oil price downturn, employing a combination of cost-cutting and activity delays, careful project selection, asset sales, and paying down debt. Companies also looked to the oil services and equipment sector to lower margins, which supported a reduction in upstream costs some 20% below 2014 levels. However, this position has reversed sharply in the first quarter of 2020, with free cash flow reverting back to 2017 levels and companies significantly increasing debt issuance to cover obligations. The financial position is likely to worsen as the full brunt of sharply declining revenues is felt through the course of the year. Moreover, there is relatively little scope this time around for further cost-cutting as most of the available savings have already been made.

At the same time, the Majors have also faced growing pressure from investors, reflecting near-term economic stress, but also growing climate risk concerns by the financial community (see below).

Many Majors have diversified spending into non-core areas: renewables and other clean energy technologies now account for up to 5% of their capital expenditure, and they are also acquiring existing non-core businesses, for example in electricity distribution, electric vehicle charging and batteries, while stepping up research and development activity. However, these areas are not at the scale or profitability to provide much of a financial buffer in the current crisis.

Providing high-dividend yields and share buybacks have historically been features of their financial strategies and ways to keep investors in the fold. The Majors took on additional debt in the 2014‑16 downturn to continue to pay cash dividends, and they also offered payment in additional shares (so-called scrip dividends), and over 2018‑19 they bought back over USD 30 billion of equity.

But in today’s market, traditional financial strategies may now be less effective. Equity returns for the majors underperformed the broader market over 2015‑19, and in the first quarter of 2020 declined sharply. Dividend coverage ratios have declined to low levels. Some companies have taken the dramatic step of cutting dividends – to date, Shell and Equinor (an NOC) have announced two-thirds cuts to quarterly payouts. Several Majors, including Chevron, Eni, ExxonMobil and Total, have announced the suspension or paring of share buyback programmes. Recently, several companies raised over USD 30 billion from debt markets to shore up liquidity and maintain commitments to shareholders. While the Majors are uniquely positioned to exercise this option compared with smaller companies, some have witnessed credit downgrades that may make borrowing more expensive over time.

The financial performance of oilfield service and equipment (OFSE) providers, already weakened over the past five years, is seeing a new wave of challenges as producing companies cut costs in reaction to the current downturn. During the oil price decline in 2014‑16, profit margins for service providers shrank from relatively comfortable levels and declined below that of the Majors as operators shelved projects and renegotiated contracts. Production companies adjusted design strategies, moving away from bespoke to supplier-standard offerings that could be delivered for less cost and with shorter lead times.

This trend fed into a period of increased industrial consolidation, including mergers and acquisitions and notable bankruptcies in several sub‑sectors. Larger players took advantage to diversify their portfolios across value chains with Schlumberger acquiring Cameron, Technip merging with FMC, and Baker Hughes and GE combining forces. The engineering, procurement and construction sub‑sector was particularly affected, marked by historically high debt ratios, restructuring and government bailouts (e.g. Daewoo Shipbuilding and Marine Engineering [DSME]). Additionally, contracting strategies have trended to putting increased financial risk onto contractors and shortening contract lengths, resulting in service companies’ reduced ability to hedge income far into the future.

Supply chain challenges manifested themselves early in the current pandemic, and service companies quickly adjusted staffing rotations and supply options where possible. OFSEs, particularly those exposed to the US shale market and drilling cutbacks, have announced capital expenditure cuts upwards of 31% in 2020. They have supplemented these cuts with cash saving measures, including stopping or reducing dividends, salary cuts, and the furloughing or laying-off of staff.

While already under pressure from the previous downturn, the current market situation may further reduce diversity among service providers. Baker Hughes announced debt restructuring and Diamond Offshore Drilling filed for bankruptcy while Weatherford International was delisted. They may not be the last companies to do so as the dynamic landscape of the service sector evolves in the downturn.

The small and medium-size independents that make up the US shale sector are among the most financially exposed to the current economic crisis and the supply shock in oil markets. They face a short-term credit crunch and also have reduced scope to increase productivity by cutting costs compared with the past.

For the shale industry, at an oil price of USD 30/bbl or less, the outlook for many highly leveraged companies looks bleak (see Fuel Supply section). Despite improving finances and efforts to pay down debt over the past four years, which resulted in reduced risk premiums, the sector’s exposure to high-yield bonds and a subsequent run-up in credit spreads in that market effectively closed a vital funding channel in early 2020. Companies are trying to extend bond maturities and keep revolving credit facilities open, but banks are also cutting exposure. A number of players have announced credit downgrades, bankruptcies, redefinition and debt restructuring as reassessments of reserved-based lending and cash flow expectations continue.

In 2020, the free cash flow position of shale companies is set for its worst year since 2015. Companies have announced significant cost-cutting and capital reduction measures. For example, Occidental Petroleum, with its heavy debt load since acquiring Anadarko Petroleum in 2019 for USD 38 billion, announced capital expenditure cuts of 54%, in addition to operational cost and dividend reductions. But opportunities to extract greater operational efficiency, as was achieved in the past by working with OFSE companies, are more limited in the current crisis.

Shale bankruptcies have continued from last year, with exits at a similar level to the immediate aftermath of the 2014-15 downturn, indicating persistent financial distress (Haynes and Boone, 2020). One of the larger independent players Whiting Petroleum filed for bankruptcy in April, and others have been early to announce restructuring in 2020 as the process continues across much of the sector.

Efforts to find the most productive areas of shale basins, adopt new technologies and expand infrastructure enabled US shale companies to double production over the past five years while continuing improving capital efficiency 40% since 2015. But the ferocity of the crisis in 2020 has been well beyond the contingencies that the industry had planned for. In addition to the price risks (against which many players had hedged), the industry was also faced with acute logistical difficulties as demand plummeted in April and available storage filled up.

Due to the steep nature of unconventional well declines, often on the order of 60% in the first year, activity reductions are set to result in production losses, especially as they are accompanied by widespread well shut-ins.

The shock of 2020 does not spell the demise of shale or of independent operators, particularly given the sector’s ability to ramp up quickly with higher oil prices, but will likely result in a dramatic restructuring of the industry landscape, including consolidation among players with well-located resources.

Looking beyond 2020, and even if oil prices recover back to 2019 levels, investment and the journey towards a more sustainable business model may depend on companies considering further innovation or efficiencies to reduce costs, or improve ultimate recoveries.

Coal power FIDs have plummeted in recent years – stemming from excess capacity and declining utilisation rates in some markets (e.g. China, India), and increased renewables and (in China) gas role in the energy mix. At the same time, the pool of capital for new developments has shrunk and financing terms have become more strict. Well over 100 financial institutions globally have announced restrictions on financing coal (IEEFA, 2020).1 Yet a large construction pipeline persists, facilitated by availability of state-backed equity, debt and guarantees, as well as long-term contracts in some Asian markets.

Since 2016, state-backed sources (including SOEs and public financial institutions) have accounted for over 60% of the financing of new coal power. The majority of this stems from SOEs building new plants on balance sheet in China, but also in India and Indonesia. A mix of private actors (power companies and industrial companies) have also taken investment decisions in these markets, as well as in other emerging Asian countries, Japan, Korea and the Middle East.

Some challenges have emerged for SOEs in the largest markets. Chinese power companies are increasingly burdened by heavy debt levels, and India’s thermal generation has come under increased financial stress with slowing demand and insufficient reforms to the distribution sector. Developments in 2020 exacerbate these trends. In Indonesia, the state-owned utility – already facing financial challenges – has seen debt burdens rise from a combination of currency depreciation and a large share of borrowing in foreign currency. It remains to be seen how changing financial dynamics will affect expansion plans, and in some cases power companies may choose to retire less efficient assets. In China, companies have shelved a number of smaller plants in recent years, while local economic and employment factors provide incentives to continue investing in new ones.

Project finance structures have accounted for a fifth of coal power FIDs, and state-backed sources of finance made up over half of these deals since 2016. Transactions have been highly leveraged over 80% debt. The three largest debt providers globally (who also provide guarantees), accounting for 35% of project debt, have been development banks and export credit agencies from China and Japan. A mixture of commercial banks from Asian countries, Chinese policy banks, and export credit agencies from India and Korea have also featured among recent major lenders.

Several commercial debt providers that were still financing in 2019 have signalled intentions to step back from the sector. Two major Japanese banks – Mizuho and Sumitomo Mitsui – announced restrictions to lending for new coal plants in April of this year. Mizuho’s announcement came in the wake of a shareholder motion filed against the bank (the first climate-related resolution faced by a publicly traded company in Japan), pointing to the influence of investor pressure. All this raises questions over the degree to which public sources may continue to fill the gap. Through March, only one new coal power FID based on project finance emerged for 2020, in Pakistan, though all project approvals were over half that for 2019 (see Power Sector section).

Most of renewables investment is carried out on the balance sheets of developers; in recent years project finance transactions (including non-recourse bank debt) have grown, especially for utility-scale solar PV and wind, following a dip in 2016. Such project finance transactions rose to over USD 50 billion 2019, reflecting ongoing risk management efforts for renewables. In 2020, transactions fell to low levels, placing increased importance on developer balance sheets to fund new projects.

As costs have declined and policies have supported deployment, the largest developers of renewables have become more profitable with returns on invested capital rising, though with slowing momentum in 2019. Leverage levels (net debt to EBITDA ratio) have edged up but remain manageable (below 4-5), indicating adequate liquidity and credit positions. Still, capital expenditures have not grown in line with earnings, suggesting that companies may be increasing holdings of cash, relative to investing, in the face of policy and market uncertainties in some areas. Despite supportive conditions heading into 2020, with the recent downturn some developers face the prospect of lower earnings, rising debt, pressure to increase capital discipline and payment and project delays in some markets (see Power Sector section). There are also questions over pricing of external finance, such as tax equity in the United States.

Government and market responses will likely influence the financial position of the industry, as well as the reemergence of project finance markets. Renewables investment largely depends on policies and contracts that help manage price risks and there continues to be a global movement towards long-term contracts awarded via competitive auctions (IEA 2019a). But with evolving policy conditions in competitive power markets, developers and financiers are increasingly required to have strategies, beyond subsidies, for solar PV and wind projects to manage revenue risks and merchant pricing exposure (IEA 2019d).

Corporate PPAs have emerged to fill this role, and with associated investments over USD 18 billion in 2019, were the largest commercial arrangement for renewables to manage market risks. Two-thirds of activity was in the United States, where corporate PPAs complement tax credits that are being reduced over time for new plants. Investment rose in Europe, where five deals linked to offshore wind were made in 2019 (Belgium, Germany and the United Kingom), Sweden led onshore wind, and Spain has emerged as the largest solar PV market. India was the third largest geography, reaching over USD 0.8 billion. Companies signing PPAs continued to diversify from IT players (e.g. Google, Facebook, Amazon, Microsoft) to consumer (Wal-Mart, Starbucks) and resource actors (e.g. BHP Group, ExxonMobil).

Corporate PPAs may become more important as a tool to manage market risk and as non-energy corporations increase ambition to directly source renewables. Still, there are questions over how the PPAs (which are moving towards shorter tenors) evolve to satisfy more buyers, and provide adequate risk management amid changing market conditions. Further effort is needed to scale them in emerging economies, where frameworks have been less accommodating.

In 2020, spending on corporate PPA projects is likely to decline with lower power demand and prices, and credit and profitability issues among corporates. While they remain economically attractive (a recent deal in Spain was struck at less than USD 40/MWh) and provide diversity in terms of procurement options, off takers may also become less able to enter into long-term contracts under current market uncertainty.

Stationary battery storage investment has risen above USD 4 billion (see Power section), supported by targets and policies that pay for the value of storage, but financing new projects can be a challenge, given the diversity and complexity of business models.

Grid-scale storage depends on the ability to monetise revenues from various services to consumers and system operators, as well as from avoided grid investment. Applications have diversified over time; in 2019, installations were mostly based on expectations to provide grid and ancillary services and support renewables integration (through hybridisation allowing variable renewables plants to operate more like dispatchable power). A smaller share went to demand shifting and bill reduction, followed by capacity provision. Project revenues often come from a combination of contracts and regulated and market pricing. Private-sector actors have financed most projects. But commercial debt remains limited for projects with short contract periods or based solely on wholesale market sales.

Uncertainties over these revenues can make it difficult to secure financing in some markets, particularly project debt from banks, and there are not enough standalone battery storage projects with cash flows and scale attractive enough to take advantage of available capital. Developers tend to favour projects with short payback periods. For projects taking FID over 2015 and 2016, most finance was estimated to came from equity sources, predominantly the balance sheets of developers. The contribution of debt has recently increased for projects taking FID in 2018 and 2019, with lending on the rise particularly in Australia, the United States and some European markets. This likely reflects availability of suitable price contracts, some increased comfort of banks with the risks, and efforts of developers to improve due diligence and structure projects that satisfy cash flow and reserve requirements.

Public sources of finance have played an instrumental role in facilitating investment decisions in some markets. For example, in Australia, most projects have benefitted either from debt provided by the Clean Energy Finance Corporation and Australian Renewable Energy Agency (ARENA) or equity from Australian state governments and ARENA. The European Investment Bank (EIB), European Bank for Reconstruction and Development and the World Bank have been active in providing debt (and technical assistance) around the world. State-backed finance is also important for electricity storage outside of batteries – in 2019, two sovereign wealth funds – GIC in Singapore and the Abu Dhabi Investment Authority – provided equity for a pumped-hydro project taking final investmend decision in India.

In contrast to the financing models for grid-scale storage, behind-the-meter storage is more linked to that of distributed solar PV. Most such installations are financed from the balance sheets of consumers and companies, often supplemented by loans, or through equipment leases and PPAs, where third parties (e.g. energy service companies [ESCOs], see below) install and retain ownership of the asset. Both models depend on significant upfront capital, which is recovered through electricity bill savings and other remuneration.

In general, the financing case depends on the contractual backbone for revenues, consumer credit quality and local factors (e.g. electricity pricing reflecting the time value of storage). In Germany, development bank KfW has provided concessional finance to installations integrating battery storage, and several aggregators have emerged offering solar PV and battery systems on a PPA basis. In emerging economies, credit for consumers and small companies is more constrained and electricity tariffs tend to be distorted more by subsidies, making financing distributed assets more challenging there. 

ESCOs provide efficiency and distributed services that are funded primarily by energy savings. Their contracting, financing and payment models enable consumers (mostly commercial and industrial actors) to overcome the upfront capital burdens of investing in energy assets that may not be part of core business.

The latest IEA survey shows that global ESCO revenues reached USD 33 billion in 2018, up 5% from the prior year and 31% since 2015. Much of this growth has occurred in China, the largest market by far, but as the Chinese market has slowed so has global growth.

Outside China, the other major markets of Europe and the United States have been relatively stable. In Europe, the role of ESCOs varies substantially by country, reflecting differences in how EU energy efficiency directives have been implemented. Markets that have grown significantly include Belgium, Denmark, Italy, Slovenia and Ukraine, while the German market, one of Europe’s largest, has stagnated. Recent clarification of accounting rules for energy performance contracts in 2018, allowing governments to record them off their balance sheets, have yet to boost activity.

Other markets in Asia have also grown. New partnerships such as the Asia Pacific ESCO Industry Alliance seek to promote knowledge sharing and private investment. Korea’s expanding market is supported by the government’s Energy Use Rationalization Fund, offering loans of up to USD 18 million. Korean ESCOs have also adopted new ways of renew their capital, with businesses selling accounts receivables to third parties at a discount in exchange for upfront cash. In Southeast Asia, ESCO development can be inhibited by electricity subsidies and regulatory barriers. Thailand’s ESCO Fund, providing equity and equipment leasing, and Energy Efficiency Revolving Fund, providing low-interest loans for bank on-lending, have helped boost activity there.

Government policies and procurement remain key drivers of ESCO activity. Many ESCOs are public entities or backed by governments, meaning they could function as effective conduits of public funds to stimulate local spending and employment in ways that deliver long-term structural benefits. Around half of global ESCO revenues come from public sources, with shares as high as 85% in the United States and 70% in Europe. In the United States, contracting by municipalities particularly benefits from financing through tax-exempt bond issuance. In China, policy incentives have driven ESCO engagement much more with private actors, which account for 90% of revenues.

Globally, most customers continue to pay for ESCO services on the basis of energy performance contracts that deliver guaranteed energy savings. These contracts are complemented by new financing approaches in some markets. In some US states, property-assessed clean energy financing, which links capital recovery to tax obligations, has helped facilitate securitisation of efficiency and renewables (see below) while some ESCOs are now looking to monetise energy savings in wholesale power markets with Pay-for-Performance contracts.

The current downturn creates new economic challenges for ESCOs, especially smaller players, which may spur consolidation. Demand for interventions to raise buildings efficiency will likely fall due to restrictive measures (see Energy end use and efficiency section). Lower electricity and gas prices may sap incentives for contracting, while supply chains may also be disrupted. That said, buildings efficiency was highlighted in the European Green Deal; as such, ESCOs may also function as a vehicle for some recovery efforts.

Community choice aggregators (CCAs) – municipal-level entities that procure bulk power, including from ESCOs, for consumers – have emerged in some areas as an alternative to the traditional utility retail model. They are most prominent in California, where regulators have designated them as load-serving entities responsible for meeting long-term renewables and zero-emissions goals, and where the revenue share of full-service utilities has fallen to 80%, from 95% a decade ago.

Stakeholders see CCAs as a new market to express local preferences for procuring renewables and demand services, with more say over tariffs, and as a funder of investment in distributed energy resources (DERs) such as solar PV, batteries and demand-side response, facilitating more flexible loads that can serve system integration goals.

However, there are challenges to realising this vision. As they are new and smaller than utilities, CCAs often lack credit ratings and a financial track record that enable financing and negotiation of contracts to support new procurement. They also still rely on utilities to manage system operations and balancing, transmission of power, and often billing services. And with more customers flocking to CCAs, California regulators and utilities face the growing challenge of managing tariffs and charges in a way that would help fund fixed investment in the grid.

Looking ahead, some features of CCAs, such as the ability to target projects that can cater to local system needs and to form regional co‑operatives, may help the integration and financing challenge. Further solutions may also come from more sophisticated contractual arrangements that value storage and demand response, as well as use excess solar PV generation for managing EV charging (Trabish, 2019). But there are also larger questions over the scalability of this model under current investment frameworks – while retail competition is present in 17 US states, only 8 of them allow CCAs.

Outside of the United States, aggregators are growing in competitive markets in Europe, Australia and Japan. In Europe, their portfolios have diversified beyond renewables, to include behind-the-meter storage and demand response; they often provide capacity to utilities or within ancillary services markets. The rollout of smart meters and digital management systems is critical to enabling this functionality (see Power Sector section). In addition to utility-led programmes, third party investments are emerging, sometimes backed by public finance. The EIB provided a loan, with an EU guarantee, in 2020 to an aggregator to support deployment of “smart boxes” to support demand side management.

With over USD 100 trillion under management, institutional investors – including asset managers, infrastructure funds, insurance companies, pension funds, private equity and sovereign wealth funds – are a large potential source of finance for the energy sector (Arezki et al., 2016).

Past editions of WEI have noted that 90% of energy investments are financed on a primary basis from the balance sheets of companies and consumers, with a smaller role for project finance (mostly loans from banks). But such mechanisms also depend on having a robust interconnected system of secondary financial sources and intermediaries, diverse investment vehicles to facilitate flows, and clear signals for investment, based on profit expectations and risk profiles (IEA, 2019b). Although a number of well-capitalised industry players (e.g. some integrated oil and gas, utility and state-owned companies) are able to make investments from retained earnings alone, there are economic benefits to tapping into wider pools of finance, at a lower cost of capital, and especially in an era of lower interest rates. Moreover, banks often face limits on their lending, particularly with regulatory constraints emerging in recent years, such as Basel III.

Institutional investors provide finance through three main channels:2

• companies – listed equities shareholding, bonds purchase
• projects – equity stakes in assets, bonds purchase
• funds or pooled investment vehicles based on energy assets.

They have long played a role in fundraising by companies, but an emerging question for policy makers is the extent to which investors can more directly help finance growing investments ahead, especially in clean energy sectors. Addressing this question in quantitative ways remains challenging, as the relationship between capital expenditures and financial flows is not well understood (EU TEG, 2019). Moreover, understanding the impact of investors on decision-making involves more qualitative factors, including corporate stewardship and recent initiatives by some public and private actors to align financial markets with calls to manage climate-related risks and energy transition goals.

The objective here is not to provide a full accounting, but to track investor and capital market trends in three main channels:

• shareholding in the top energy companies
• acquisitions and refinancing of energy projects
• financial flows to pooled vehicles (securitisation and yieldcos) for clean energy.

The section after assesses from a broader standpoint a related trend – the recent dramatic rise of sustainable finance, and related regulatory developments, and how this trend also relates to energy investment.

The events of 2020 illustrate how rapidly financial markets can shift. The risk management practices of investors may adjust to liquidity issues and changing risk profiles of real assets. While this analysis takes a longer view, volatility casts uncertainty over some trends.

Institutional investment in energy most commonly comes in the form of traded securities on equity and debt capital markets. Among the top 25 listed energy companies, by capital expenditure, investors accounted for nearly USD 1 trillion, or 25%, of the market value of these firms, as of early 2020. Excluding Saudi Aramco, whose initial public offering took place in late 2019, the capital markets represented nearly 40% of ownership. Institutional shareholding of listed equities varies by type of company, and investment opportunities tend to be more prominent with firms without recourse to government funding. For the private-sector energy companies, investors account for over half of shareholding, while for SOEs the share is less than 10%.

Over 80% of institutional capital for these companies comes from asset managers and brokerages, the largest holders of which include BlackRock, Vanguard, the Capital Group and State Street Global Advisors. While difficult to quantify, the investment strategies of the largest asset managers include a sizeable component of passive funds that follow established broad indices, compared with funds based on active strategies, where asset managers more frequently buy and sell shares. Pension funds and insurance companies, which typically employ active strategies, but with long time horizons, accounted for less than 10%, followed by sovereign wealth funds.

The first quarter of 2020 was marked by extraordinary movements in financial markets, with the market value of oil and gas companies, in particular, falling precipitously on the back of economic risks from the coronavirus, and prospects of a near-term oil supply glut. Even before these events, however, there was some evidence of investors pulling back from the largest energy companies. From the start of 2018 to the end of 2019, institutional investors pared shareholding in this group by around 6%. Share buybacks by some companies (e.g. oil and gas majors) during the past two years likely had influence on this, and there is considerable divergence in holdings among companies, partly reflecting investor uncertainty over how well some large players in the energy industry can position themselves in a changing market environment. The pullback included investors with sizeable passive holdings – as indices rebalanced, due to changing market prices and weightings, so did passive investor positions.

The energy investment implications of investor shareholding has both financial and corporate governance components. The buying and selling of shares is integral to corporate fundraising activities and the cost of capital, which can influence the selection of projects based on evolving risk and return requirements of investors, who have fiduciary duty to prudently manage the financial assets of their beneficiaries.

A larger question is the extent to which normally passive investors may become more active, seeking to wield more influence over energy companies in terms of strategy and decisions over capital expenditures and dividends. Stock ownership allows investors to vote on company issues and the selection of the board of directors at annual shareholders meetings. Already, some investors are taking stronger action to engage energy companies on sustainability issues (see below) and one indicator of change is the near-doubling of stewardship teams of major asset managers between 2017 and early 2020 (Mooney, 2020). Further monitoring is needed to assess investor commitments and industry impacts in this area, particularly amid the current economic downturn.

At more than USD 140 billion in 2019, the market for acquisitions and refinancing of energy assets (primarily large-scale energy supply and infrastructure projects) has more than doubled over the past decade, fuelled by ongoing industry restructuring in the oil and gas and power sectors and facilitated by accommodative financial conditions. While refinancing of existing assets does not directly add new projects to the mix, it plays an important role in energy investment by creating opportunities for developers to recycle their capital, reduce financing costs and improve confidence to undertake new projects (see below).

Institutional investors have played a growing role in this market, accounting for over USD 30 billion, nearly a quarter of transactions, up from less than one-fifth in 2010, driven by an ongoing search for yield in a low interest rate environment, and growing interest in ways to directly invest in low-carbon energy projects to meet sustainability goals (see below). Finance has come through both debt and equity channels, though in the past five years, their provision of project debt and purchase of project bonds has risen, in part due to the shifting nature of transactions to power- and infrastructure-related assets.

During the past five years, over 80% of acquisitions and refinancings by institutional investors have come in geographies with relatively liquid and deep capital markets (i.e. North America and European countries), with the United States alone accounting for one-third. Financing activity has remained more limited in emerging economies, where investment risks are higher and capital markets are less developed, though transactions in India and in Brazil, where the government has promoted tax-exempt local infrastructure bonds, picked up the past three years; in China there is a lack of disclosed transactions, which makes assessing the true level of activity more challenging.

There has been a shift by investors from the refinancing of upstream oil and gas in the first half of the decade towards renewables, which offer relatively predictable cash flows from long-term contracts. The investor portion of renewables transactions was around USD 12 billion in 2019 (from a record USD 17 billion in 2018), led by offshore wind. Interest in oil and gas infrastructure (pipelines and LNG) projects has also grown, supported by master limited partnership structures in the United States offering tax pass-through benefits, and in power and heating networks with remuneration typically based on regulated rates of return.

In 2019, the largest deals with investor participation included refinancing of the 588 MW Beatrice Offshore Wind Farm (United Kingdom); acquisition of the Veja Mate Offshore Wind Farm (Germany); refinancing of the Sabine Pass LNG and Creole Trail pipeline (United States); and acquisition of Energias de Portugal’s (EDP’s) hydropower portfolio (Portugal). Early indications from 2020 suggest that investors with cash to deploy are becoming more disciplined and awaiting clarity on price discovery in financial markets. That said, financing existing assets with reliable cash flows, such as renewables, may remain attractive in the face of market volatility.

Looking ahead, there is considerable scope for more investor participation, particularly in renewables, where their refinancing activity is equivalent to about 5% of annual capital expenditures. Scaling up project-based institutional finance depends on policies that support cash flow profiles aligned with investor risk-return profiles and reduced barriers to participation as well as investor efforts to build in-house skills and manage scale and liquidity issues associated with direct investments. This is an area ripe for further work.

While investor capital for refinancing and acquisitions does not directly support new project development, it can have a powerful indirect effect. Investors provide an exit opportunity for developers, allowing them to swiftly recover their capital and reinvest this in new projects.

There are also economic benefits. Some renewables developers have been able to enhance their equity returns through a combination of improving project output, reducing capital costs and employing greater leverage from banks. Moreover, selling operating projects – which can match the lower risk and return requirements of investors – provides an underutilised means to enhancing returns. For an indicative onshore wind project in Europe, selling a 50% stake of the investment to an institutional investor with a return expectation of 5% can help boost equity returns for the developer from single- to double-digit rates.

These economic benefits can also support more affordable deployment of renewables. Substitution of institutional capital for a part of the original equity reduces the lifetime cost of capital for projects and can enable developers to bid for power purchase contracts at lower electricity prices, while maintaining the same level of expected returns. For example, analysis by the Development Bank of Japan suggests that a 2-3 percentage point reduction in the weighted average cost of capital (from refinancing and acquisitions by institutional investors) could translate into a nearly 15% reduction (from JPY 36/kWh) of feed-in tariff levels for offshore wind in Japan (Yasuda, 2019).

Creating such opportunities requires confidence over potential exit opportunities when developers evaluate the financial case for investing in a new project. Greater participation of investors in renewables investment could be a factor in reinforcing these expectations. That said, this model can also entail risks for developers in a changing interest rate environment when return expectations shift for investors between the period of project development and sale.

Institutional investors can direct capital towards a universe of project funds and pooled vehicles (i.e. those that aggregate a portfolio of assets) based on energy investments, but it can be challenging to assess their links to real assets. One mapping in Europe tallied over EUR 20 billion in green funds, but their energy composition is not entirely clear (Novethic, 2017). Some dedicated funds have emerged around clean energy (e.g. storage and efficiency funds launched in 2019 by SUSI Partners), but a number remain unlisted.

Securitisation and yieldcos aggregate portfolios of loans, receivables or projects from the balance sheets of banks and developers. These portfolios are then issued as listed securities. They are well suited to directly refinancing small-scale assets (e.g. efficiency, distributed solar PV), whose transaction sizes would not attract investor capital, and can also work for larger projects. By pooling assets, these vehicles diversify and spread risks across investors, enabling a lower cost of capital.

Securitisation of energy into listed debt securities has accelerated in recent years, though dipped in 2019 to under USD 28 billion. Over the past three years, three-quarters has come from issuance of green MBS (loans to properties making demonstrated efficiency or renewables investments) by Fannie Mae (US agency which purchases loans from other lenders), though increased competition in the mortgage market has slowed its activity. ABS based on leases and loans for distributed solar PV and efficiency/renewables investments made under PACE payment mechanisms (i.e. tax liens) were over USD 3 billion in 2019. Most securitisation is in the United States, but energy assets account for only 1% of the USD 2.5 trillion of ABS/MBS issued there in 2019.

Securitisations of clean energy depend on underlying cash flows of many small assets; policies often help to manage credit risks and enhance technical and legal standardisation. Fannie Mae provides guarantees for its mortgages, and US-based solar PV securities are largely based on revenues under net metering schemes. PACE programmes (available in 20 US states) provide a standard framework and link loan repayments to tax obligations, encouraging lenders to provide loans on better terms; there is now a movement to develop PACE in Europe. Some state-backed Green Banks are now facilitating securitisation in their local markets (Green Bank Network, 2019).

There is some evidence such assets can have credit risk advantages (see below). The ability to refinance through securitisation can also encourage banks to develop clean energy financing products – e.g. Barclays in 2018 launched a green mortgage product which offers a 10 basis point discount to traditional loans. So far, securitisation has been used on just a few large-scale projects (e.g. gas power, networks), but Singapore recently launched a USD 2 billion platform to encourage infrastructure refinancing via this mechanism.

Yieldcos – listed equity vehicles holding multiple operational renewable energy projects (which can also be suitable for efficiency), typically benefiting from power purchase contracts – saw a boost in fundraising over 2014‑15. But experiences have considerably varied by market, with differences in how assets are aggregated and capital is structured impacting financial performance (Donovan and Li, 2018). These structures also may not offer suitable diversification, with the parent operator common to all assets. This has called into question some of their cost of capital benefits, so far, relative to traditional utility finance.

An important question for investors and policy makers looking at securitisation pertains to whether clean energy assets can manage cash flow risks better than other options, enabling lower cost of capital.

Some evidence comes from the ratings of ABS based on PACE financing. Residential properties with a PACE assessment had lower tax delinquency rates than benchmarks, and loan prepayment rates had come in higher than original assumptions, which were credit-positive factors for a new asset class (Nocera et al., 2018). Part of this performance may stem from the type of homeowner who invests in efficiency and renewables upgrades, but it likely also reflects the payment security provided by the PACE mechanism itself.

It is further possible that energy savings from efficiency projects can enhance property values and translate into lower credit risk for mortgages. A recent Bank of England study of UK residential mortgages found that those properties with high degrees of energy efficiency (as classified by energy performance certificates [EPC]) had somewhat lower default rates than low-energy-efficient properties, even when controlling for household income levels and other factors.

These pieces of evidence suggest there may be financial performance benefits for clean energy and efficiency, also reinforced by socio‑economic factors and policies. This has implications for financial regulator discussions in Europe on the capital treatment of assets based on environmental attributes, which can further impact energy project economics. In 2020 the Central Bank of Hungary instituted a preferential capital requirement programme for banks if they apply an interest rate reduction of 0.3% on mortgages to improve the energy efficiency of the underlying property or refurbishment loans (mortgage rates were 4-5% in 2019). The EU Energy Efficient Mortgages Initiative is developing a pilot scheme that has demonstrated lower default risks from mortgages based on energy-efficient homes in the Netherlands.

Still, it is not clear that green debt always outperforms conventional bonds (see below) and regulators lack an empirical track record. Further analysis is needed, including data collection at asset level and translation of performance metrics into credit model parameters.

As the roles of renewables and efficiency rise in the energy system, some regulators are looking at financing strategies for managing turnover of the existing capital stock, particularly regulated coal and gas assets with changing utilisation that makes them less economic.3 In addition to traditional utility finance tools – e.g. accelerated depreciation and adjustments to equity returns – the practice of securitisation features as a way to refinance obligations and take advantage of the lower cost of capital for debt compared with the equity that makes up part of the utility cost of finance.

Since the mid-1990s, US utilities have securitised over USD 50 billion of assets, mostly before 2005 in the wake of state-level deregulations, with 80% of the use of proceeds going to diverse stranded costs and storm damages. In 2016, securitisation funded retirement of a nuclear plant, though little activity has followed.

To obtain a high credit rating, such securities need to be backed by regulatory guarantees. While this places a burden on ratepayers, it can be more affordable than other financial options for early retirement. Refinancing with debt can also mean a haircut for equity investors and may be less attractive for the utility (e.g. versus depreciation). In this light, some utilities are looking at securitising and then reinvesting the proceeds from unprofitable coal power generation into renewable power (“steel-for-fuel”), to create a new equity return and support transition goals (Lehr and O’Boyle, 2018).

Overall, the question of “who pays” for assets with changing utilisation profiles is not easy and securitisation may require special regulatory conditions put in place to make it possible. As electrification increases in the global energy system and decisions for gas networks consider their potential to deliver different types of gas in a low-emissions future, securitisation may be also looked upon in some markets – among other options – for helping to manage energy infrastructure.

In recent years, there has been a broad push by investors and policy makers across three areas to align decision-making in the financial sector with improving sustainability in the real economy. This creates opportunities and challenges for the allocation of capital in the energy sector, as well as the engagement of investors with energy companies.

First, investor pressure is focusing corporate attention on climate-related risks through engagement and divestment movements. Over the past decade, climate-related shareholder resolutions, which commonly seek to improve disclosure or align the strategies of companies with a more sustainable pathway, have strongly increased, especially for oil and gas companies. Meanwhile, burgeoning investor collaborations, such as the Climate Action 100+, increasingly seek to facilitate corporate engagement on sustainability. Earlier this year, the world’s largest asset manager, BlackRock, announced new disclosure requirements, climate-related engagement and criteria for its investments. More banks, pension funds, insurance companies and investors are limiting exposure to certain types of fossil fuel projects; the primary focus has been on coal, but restrictions are increasingly seen on some oil and gas projects.

Second, there is a growing need for financial institutions to identify and evaluate the financial risks associated with energy transition. Doing so requires better corporate disclosure on energy and environmental performance, as well as assessment tools. Some jurisdictions (e.g. France) have already mandated investors to report the sustainability of their portfolios, while recommendations of the Task Force on Climate-Related Financial Disclosures and those by central banks (e.g. from the Network on Greening the Financial System) have encouraged voluntary reporting and risk analysis. But metrics are incomplete – for example, less than 60% of S&P 500 firms report any emissions data. Sustainability disclosure and accounting standards remain fragmented, with several frameworks in existence (Gibbs, Portilla and Rismanchi, 2020). There is also lack of agreed benchmarks (e.g. scenarios) to assess reporting consistency with climate objectives over different time horizons.

A number of initiatives to classify sustainable investments have emerged, as a way of clarifying financial decision-making. The most comprehensive framework has come from Europe, where the proposed EU Taxonomy is set to require investors to report from 2021 portfolio alignment based on sustainability criteria for 70 different economic activities. Applying the taxonomy will require better financial data and analyst interpretation – an indicative look at Europe’s top utilities suggests that current company reporting does not yet provide the granularity needed to always map criteria onto key financial metrics such as capital expenditures and sales. A new EU Climate Benchmark regulation seeks to provide transparent measures for investors to compare the financial performance of their own strategies.

There are also challenges in agreeing what is meant by “sustainable” in different markets around the world. Other taxonomies are emerging in Canada, China and Malaysia, which seek to base criteria on local conditions and varied pathways for energy transition.

How might recent market volatility affect momentum? The financial crisis of a decade ago may have helped to refocus investor attention on sustainability (IFC, 2009). The European Union continues to push forward on consultations related to its Action Plan on Sustainable Finance. While sustainable finance flows (see below) have slowed, as investors reassess exposure across all asset classes, such instruments may also play a role in the financial and fiscal policy responses.

Among listed investments, sustainable debt securities – including labelled green bonds, green and sustainable loans, and sustainability-linked debt – may provide investors the clearest route to capital allocation for clean energy and other green activities.4 They may also be particularly suited for small-scale renewables and efficiency investments, which are difficult for investors to fund directly. These advantages stem from labelling and certification (under frameworks such as Green Bond Principles, and more specific evaluations, e.g. Climate Bonds Standard). Still, frameworks are not always harmonised across markets, and as labelled securities grow beyond green bonds, their impact and uses become more complex to evaluate.

In 2019, sustainable debt issuance was nearly USD 450 billion, up from near USD 250 billion, though it remains a fraction of overall debt issuance at just over 5%. So far in 2020, issuance has proceeded at a slower pace, on an annualised basis, reflecting wider market volatility. Green bonds, whose labelling corresponds to projects and activities defined in the bond, represented 60% of 2019 issuance, led by government actors (US agency Fannie Mae, German development bank KfW, and Dutch and French governments). Financial institutions, which mostly use proceeds for on-lending, were the largest issuers, but corporations (especially power) grew fastest. Sustainability-linked debt, based on performance rather than activities, rose to 30% of issuance.

With over 80% of issuance from the United States, Europe, China and mature markets, there is scope for green bonds to play a greater role in financing companies and projects in emerging economies, where there are higher credit constraints and investments rely more on balance sheets. So far, the Philippines and India have led activity, with green bonds issued by large conglomerates, mostly to finance renewables.

Since 2014, overall sustainable debt issuance has grown over tenfold. This pace has far exceeded that for new capital expenditures in renewables and efficiency, which have remained relatively stable over the period(see Power sector and Energy end use and efficiency sections). These securities have so far had more of an impact on improving funding for existing programmes, refinancing assets and facilitating sustainability dialogue between investors and companies. Some mismatch may stem from availability of opportunities that meet liquidity and asset allocation requirements for investors, but it may also represent the different speeds at which sustainability efforts are proceeding in the financial markets compared with policies and decision-making for new capital formation for real energy assets.

There is also debate over the financial benefits – i.e. do sustainable instruments lower the cost of capital or enhance returns, improving the affordability of clean energy investments? So far, credit risk profiles and issuance costs are broadly comparable to that of conventional instruments, though there are periods of outperformance. In the first quarter of 2020, returns for green bonds were in line with that for global investment-grade bonds. New types of instruments are now seeking to better tie financial performance to environmental outcomes– e.g. interest rates for a USD 2.5 billion Enel bond issued in 2019 are tied to goals for renewables capacity and emissions levels.

Labelling and standards for green bonds give investors confidence that proceeds will be used for sustainable aims. Still, this can exclude actors with businesses based on fossil fuel supply or consumption as well as environmental activities that fall under so-called “shades of green”.5 Such areas still play an important role in achieving climate aims. For example, meeting climate change goals requires significant reductions in methane emissions for upstream oil and gas.

Transition bonds are being marketed to help issuers, such as oil and gas companies or energy-intensive industries, fund improvements in sustainability, despite the relatively high carbon footprint of these actors. The market remains small for now, but as investors and banks reassess climate-related risks, such instruments may help to fill potential financing gaps for the project developers and provide more nuanced approaches to capital allocation by the financial community. For example, oil and gas major Shell recently signed a USD 10 billion credit facility where interest payments are linked to progress in emissions reductions. In shipping, a difficult-to-decarbonise sector, Teekay Shuttle Tankers is seeking to raise funds for emissions reductions through new vessels that can use LNG and propane mixes as fuel (Fjell, 2019).

At the same time, transition bonds may not provide the transparency, benchmarking or level of improvement that some investors with strict sustainability criteria apply to capital allocation. And they may not fit within tightening criteria for green bonds, such as under the proposed EU Taxonomy. Some stakeholders have suggested that transition bonds may increase the risk of corporate greenwashing by focusing on incremental improvements rather than long-term climate solutions. In sum, given the complexity of solutions to reach sustainable development goals and a need to scale up investment for a range of technologies, by a large range of actors, transition bonds are likely to remain a part of financing and policy discussions, though likely with increased focus on guidelines to improve standards and transparency.