IEA (2019), World Energy Investment 2019, IEA, Paris https://www.iea.org/reports/world-energy-investment-2019, License: CC BY 4.0
Energy investment has a strong link with country-level financial conditions. Deep availability of capital from private institutions, liquid capital markets, and access to domestic and foreign sources, complemented by limited public finance, are hallmarks of a supportive enabling environment.
In 2018, one-third of energy investment was concentrated in areas with both well-developed financial systems and good access to foreign capital (higher- level). This category includes markets such as the United States, a number of European countries. and Australia, where private credit, equity markets . and foreign sources of capital all play a relatively strong role in the economy.
Around 40% of investment was in economies with mixed conditions. Some large markets, such as China, have relatively well-developed domestic financial systems but lower levels of FDI in the economy. Others, such as Brazil and Mexico, have benefitted from rising shares of FDI in recent years but have relatively constrained domestic finance. Countries in Southeast Asia are highly mixed.
A quarter of spending was in areas with lower levels of development, where state-backed capital plays a stronger role. This category covers a wide spectrum. In India, the availability of private credit has increased substantially in recent years. In contrast, Indonesia and much of sub-Saharan Africa, outside of South Africa, are more constrained for capital, particularly for early stage project preparation.
Looking ahead, investment gaps are largest in areas currently with mixed or lower-level financial conditions, i.e. those areas with relatively high capital constraints in their economies. In the SDS, 70% of energy investment is projected in such regions, meaning that the need to boost investment in sustainable energy is highest in the regions with the least-developed financial sectors.
Energy investment decisions are made with an eye towards profitability but also by perceptions of risk and business factors. Recently announced intentions by some actors to shift their capital allocations to a different mix of fuels and technologies merit a look at some of the financial and non-financial drivers.
The two main reasons given for capital reallocation are: 1) to invest more in sectors seen as supporting energy transitions or, 2) to invest less in areas now perceived as riskier. For example, a few European oil and gas majors now plan to invest more in power, while many utilities, whose portfolios were previously oriented towards thermal power, have boosted activity in renewables, grids, and end-use services. A number of financial investors have signalled restrictions on financing coal assets.
The SDS includes a modest overall increase in investment but a major capital reallocation towards low-carbon power and grids. However, today’s energy market trends are not at all consistent with the SDS, with rising emissions and insufficient deployment of many clean energy technologies (IEA, 2019c).
While increased investment activity by power companies in renewables and grids is reflected in this report’s data, capital reallocation is less evident in the data for the oil and gas industry. So far, oil and gas activity in power has come more from company acquisitions (e.g. in solar PV, EV charging, and batteries), while capital spending on renewables has remained less than 1% of that for fuels.
Slides 121-122 illustrate how returns and risks for investments by listed companies in different energy sectors are evolving by comparing two measures: the profitability of investments (ROIC) and the cost of financing them (WACC). The difference in the metrics provides an indicator of an industry’s ability to create shareholder value, a driver for any decision to access and allocate capital.
The financial measures show that the oil and gas and power sectors are very different in terms of profitability and financing. Historically, oil and gas has been characterised by higher returns, higher cost of capital, and greater volatility. More capital-intensive power has shown lower profitability but with lower cost of finance and a degree of market volatility that is more balanced with regulated assets.
Over time, returns on investment for top oil and gas companies (majors and E&P by current production) dropped from high levels as market fundamentals and oil prices weakened. This was followed by a recovery in the past three years, thanks to higher prices, cost reductions and careful project selection.
Industry funding costs, which reflect a strong share of equity, were stable until 2014 when market data showed a rising return on equity required by investors. This stemmed, in part, from an increase in volatility, or systematic risk, associated with company stock prices, as expressed by a higher beta.
Returns on investment for top power companies, ranked by current ownership of solar PV and wind, declined over the past decade, with weaker profitability for thermal generation exposed to lower wholesale prices. Returns improved somewhat in the past three years, benefitting from investments in assets with more contracted revenues (e.g. renewables) as well as higher power prices.
Declining funding costs partly cushioned lower returns in power, where debt plays a bigger role. Debt became less costly with lower interest rates but also from the improved maturity and risk profile of renewables. With increases in US rates in 2018, debt financing costs rose. But required equity returns fell over time from reduced volatility, indicated by a declining industry beta.
Smart grid companies (illustrating another part of the power supply chain) have seen more consistent, positive performance, buoyed by sustained demand for new equipment and regulatory support for networks. Funding costs reflect a high influence of equity given a focus on technology development.
Putting the pieces together, the recent movement in financial metrics suggest better performance, on average in terms of average shareholder value creation, by power industries focused on energy transitions than by oil and gas companies. This may help to explain the interest by some oil companies in cross-sector investment, with potential benefits from diversification and new business development.
However, investment decisions in the energy sector are shaped by complex factors that are difficult to quantify, including demand expectations, human capital and supply chain issues, business synergies, as well as the financial and reputational risks from potentially stronger climate policies.
So far, many oil and gas companies (e.g. in the United States) are seeing operational improvements and a focus on higher-return core assets as a better recipe for long- term profitability than investing elsewhere in energy.
Supportive policy frameworks have been instrumental in encouraging investment in renewables, but there are questions over how these policies will evolve and what this might mean for risk allocation between public and private actors (see Key theme on Financial risk- management for renewables).
In sum, current market signals are not incentivising the major reallocation of capital needed to reach the goals of the SDS. This also suggests a need for better understanding of the evolution of the risks, returns, financing sources, and other factors that would accelerate energy transitions.
Since mid-2016, the majors have enhanced their financial conditions due to a combination of higher oil prices, improvements in operational efficiency, and cost reductions. In 2018, free cash flow reached almost USD 90 billion, a level not seen since 2008.
The improvement in financial conditions has also allowed the majors to reduce the high leverage levels reached during the downturn period while returning value to shareholders. After having increased their debt by more than USD 115 billion during 2014-16, in the last two years, companies have decreased their debt exposure by around half of this amount.
During the 2014-18 period the majors maintained high dividend levels, compared to other industries, distributing nearly USD 50 billion per year on average to shareholders. They also re-introduced share buybacks; in the 2018, these reached the highest level since 2014. Nevertheless, on a total return basis, the oil majors underperformed the market benchmark during this period, with relatively high dividends partly offset by bouts of weaker share prices.
Independent US shale companies have typically relied on new debt, selling assets or issuing new equity for financing their operations. But their call on external financing has been reduced since 2016, thanks to efficiency in their activities, cost reductions, and a more disciplined approach to balancing the investment and cash flow generated by their own activities.
While shale companies in aggregate overspent also in 2018, the ratio between capex and cash flow has constantly declined from almost 2 in 2015 to just over 1 in 2018. Furthermore, shale companies have paid back debt and began to return cash to their shareholders via share repurchases.
In mid-2018, we anticipated that the shale industry was on the verge of finally achieving a positive free cash flow for the entire year. The US shale sector indeed showed significant improvements in the financial sustainability of its operation, with its cash flow rising by about 50% while investment increased by only 20%. Ultimately, the shale industry as a whole did not turn a profit in 2018. Two main factors during the second half of 2018 led to this result:
- Shale companies accelerated spending throughout the year as a response to oil prices steadily increasing throughout the first nine months of 2018.
- Bottlenecks in the evacuation pipeline capacity from the Permian meant large price discounts from the West Texas Intermediate (WTI) price, lowering financial income for shale operators.
Assuming no significant decline in the current level of oil price (WTI price of USD 60/barrel), we estimate the shale industry be on track to finally achieving profitability in 2019 for three main reasons:
- The pressure coming from investors makes independents very likely to stick to anticipated guidance, indicating cash flow neutrality on average at WTI USD 50-55/barrel prices. Although WTI prices have increased by more than 30% in Q1 2019, companies reiterated their commitment to previous plans.
- Takeaway capacity in the Permian is less of a constraint as new pipelines are entering operation.
- The large accumulation of drilled but uncompleted wells (DUCs) can represent an additional source of oil growth with a limited injection of capital. Preliminary data show that the number of DUCs completed in the Permian has been accelerating since February 2019.
About 85% of power investments in 2018 were financed on the balance sheets of utilities, independent power producers, and consumers (for distributed generation). The use of project finance for financing new projects has grown in recent years, with its largest contribution now in the utility-scale renewable power sector. The average debt-to-equity ratio in project finance has generally been around 80:20.
Project finance plays a significant role in the United States where recent tax code changes have not undermined the availability of tax equity for solar PV and wind. In Europe, while project financing for onshore wind has been stable, that for offshore wind has grown as the maturity of the technology has increased and the risks have fallen, thanks to competitive bidding for long-term contracts and, in some markets, system operators assuming grid connection risks. Renewable project finance has also spread into Australia, Japan and Latin America, boosted by policies to help manage the risks.
Over 95% of power sector investment was made by companies operating under fully regulated revenues or long-term contractual mechanisms to manage the revenue risk associated with variable wholesale market pricing. In many countries with competitive wholesale markets, short-term price signals alone remain too low to trigger investments in the most capital-intensive assets (IEA, 2018c).
In 2018, around 45% of utility-scale renewables spending was in projects whose contractual remuneration is determined by competitive mechanisms. These are mostly government schemes - such as auctions, which play an increased role in Europe, India and have started in China, among others – but include other arrangements, such as corporate procurement, which is growing rapidly (see below).
Grids investment depends on planning and regulation; on a per capita basis, it is highest in those markets with cost reflective tariff setting and utilities who can adequately recover their fixed costs.
Cash flow certainty is critical for renewable projects to manage risks and facilitate finance. Nearly all utility-scale investments to date benefit from long-term pricing under policy schemes – e.g. auctions for contracts and feed-in tariffs – and physical power purchase agreements with utilities subject to purchase obligations. Looking ahead, most investments benefit from such policies (IEA, 2018b, 2018c).
However, governments face trade-offs in addressing investor risks, affordability concerns and system-friendly development. For example, European market design efforts seek greater integration of variable renewables into markets, and there has been a policy shift from feed-in tariffs to auctions for market premia and contracts-for-differences, which provide revenue certainty, but can increase marketing risks. In the United States, the Production Tax Credit (PTC) is being phased out over time for new wind plants.
Developers can also face risks in the context of existing policy schemes. These may occur when there are mismatches in project capture prices and reference prices used to determine remuneration (which can arise under a contract-for-differences); in project operations extending beyond the horizon of support (some incentives are available for only 10-15 years); as well as unexpected regulatory changes.
In competitive power markets, industry and finance players are increasingly required to have strategies, beyond subsidies, for solar PV and wind projects to manage potential revenue exposure to short-term market pricing over their lifetime. At the same time, there is a growing trend among non-energy corporations to procure renewable power directly, independent of government plans (IEA, 2017).
Slides 138-147 illustrate structures and mechanisms that investors are adopting in response to these trends and assess implications for financing renewables. Successful use of these options depends strongly on the underlying regulatory framework, electricity market design and financial system.
Physical PPA – a bilateral commercial contract where a counterparty (usually utility) purchases at a set price and takes physical delivery of power from a generator. Physical PPAs are common in both competitive and regulated market structures (though the terms and rules can differ greatly) with the duration of contracts for solar PV and wind plants typically ranging from 10-25 years.
Financial PPA – (i.e. corporate/synthetic/virtual PPA and contract-for-differences) – a bilateral financial contract where a counterparty agrees to a fixed purchase price, but does not take physical delivery. Generators sell into wholesale markets and the difference between the reference market price and agreed fixed price is reconciled between parties. Financial PPAs are used in the United States, Europe and other power systems where third-parties transact and are often coupled with the sale of renewable certificates or guarantees of origin.
Financial hedge – a bilateral financial contract where a counterparty (often a bank) provides fixed payments in exchange for a variable power price based on a pre- determined settlement point. Bank hedges of up to 12-13 years have been used in the United States.
Proxy revenue swap – a bilateral financial contract where a counterparty (e.g. insurance company) provides a hedge against variable project revenues from uncertain production volume, timing of generation and electricity prices. 5-10 year swaps have been used in the United States and Australia.
Forward contracts – standardized financial contracts for electricity traded on market exchanges for settlement at a future date, involving fewer transaction costs than bilateral options. Where available, electricity forward contracts are traded liquidly usually only 1-2 years ahead, but other commodities (e.g. gas) have liquidity further into the future.
Select renewable power projects with business models reportedly based on “merchant” or “unsubsidized” pricing
|Project||Market||Status (reported operation date)||Reported business model and financial risk management features||Policy & regulatory enablers and other revenue streams|
|Willow Springs Onshore wind (250 MW)||United States (Texas)||Operating||Wholesale market sales with bank financial hedge||Production tax credit & state-led transmission programme (CREZ)|
|Port of Hirtshals Onshore wind (17 MW)||Denmark||Construction (2019)||Wholesale market sales with financial PPA from trading company||Auction framework for development rights|
|Hollandse Kust Zuid–1&2 Offshore wind (750 MW)||Netherlands||Construction (2023)||Wholesale market sales; no reported commercial risk management features||Auction framework for development rights; TSO provision of grid connection|
|Talasol Solar PV (300 MW)||Spain||Announced||Wholesale market sales with 10-year financial PPA with undisclosed counterparty||Partially financed by European Fund for Strategic Investments|
|York Solar PV (35 MW)||United Kingdom||Construction (2019)||Wholesale market sales; hybridisation with 27 MW battery storage||Ability to sell grid and ancillary services to TSO|
Merchant projects are those whose revenues are derived primarily from short-term wholesale market pricing; TSO = transmission system operator.
Accounting for investments based on risk allocation among private and public actors is challenging. But understanding potential risks and availability of tools to manage them is key to financing.
While few projects have proceeded based on wholesale pricing alone, there is growing interest in finance and technology arrangements to manage risks in competitive markets. These options can act as a complement to policy-based remuneration and provide investment opportunities when availability of physical PPAs may be limited. However, as they can raise project complexity and require private actors to take on more risk, they have potential implications for financing costs, with more reliance on equity and less on debt, which is less able to absorb pricing volatility. More research is needed in this area.
Financial risk management options are no substitute for supportive regulations, appropriate market design and technology development. For example, several offshore wind developments in Europe plan to operate based solely on short-term pricing, but the viability of these projects depends on the long-term outlook for market prices, on the system operator taking on the risks associated with developing and funding the grid connections (up to 15% of the project cost), as well as anticipated enhancements in turbine technology.
Of the arrangements described here, corporate PPAs have emerged as the largest, and their investment grew by one-third in 2018 to nearly USD 15 billion, now accounting for over 5% of global solar PV and wind spending. Their use by large consumers with suitable demand profiles and strong credit ratings has allowed for more debt financing. Still, making a larger energy impact would require a lot more investment – e.g. a sevenfold growth in cumulative spending would be needed to cover 10% of current commercial and industrial demand in the United States and Europe. This suggests involving a greater pool of companies, which could raise challenges in credit risk evaluation and project structuring.
Corporate PPAs have grown in areas (e.g. the United States, Europe) with regulations for contracting and reselling power; utilities who provide billing, balancing, and physical delivery services; and certification that facilitates additionality. In the United States, renewable tax credits have enhanced their use. Still, these contracts (typically 10-15 years) may not fully manage risks over a project’s lifetime.
Other bilateral options have garnered interest. Bank hedges were used in a quarter of 2018 US wind installations, enabling projects to manage price risks from selling output in wholesale markets and complementing the production tax credit (available to projects for 10 years). In Australia, a solar PV project reached financial close in 2018 based on a proxy revenue swap with an insurance company.
Use of exchange-traded forward contracts is currently more limited. In European markets, futures only allow for baseload power price hedging (currently at EUR 30-50 [EUR]/megawatt hour for 2023-24), and liquidity is limited more than 2 years out. Still, some energy traders reportedly offer longer contracts on a bilateral basis and, industry interest has grown in the use of gas forward contracts, which have longer-dated liquidity and can be structured to provide a proxy for electricity prices (Aydin, C., F. Graves and B. Villadsen , 2017).
The ability of financial contracts to manage market risks depends on their tenor and how they are structured. Even with a fixed-price contract, projects may still be exposed to basis risk, arising when the price at the settlement point differs from the local price available to the plant, or profile risk, when the timing of revenues received by the plant deviates from that of the contractually determined price.
Finally, some renewables projects have been paired with storage, enabling some dispatchability; this accounts for 10% of grid-scale battery installations. Business models for such plants are complex, relying on a mixture of capacity contracts, grid services provision and wholesale market sales.
The market for energy service companies (ESCOs) – who provide energy services and energy efficient equipment to end users – is growing steadily. The global value of the ESCO market (by energy performance contract revenue) was nearly USD 30 billion in 2017, up 8% since 2016. Much of this growth is occurring in China, the largest market by far.
Government policy remains a key driver of ESCO activity. In China, policy incentives have driven ESCO engagement in the private sector, while government procurement rules have been a barrier to further development in the public sector.
In North America, public sector asset owners are able to obtain debt on favourable terms to finance ESCO contracts. In Europe, where the ESCO market is 10% of the global total, the European Commission recently clarified the terms under which an EPC can be accounted for off-balance sheet. The impact that these changes will have on the European ESCO market is still to be seen.
Globally, nearly half of ESCO investment is for private sector customers. Most agreements between customers and ESCOs are underpinned by energy performance contracts that clarify ongoing payments and commit the ESCOs to installing equipment and guaranteeing savings.
Digital technologies, such as sensors and smart meters, that provide real time information on equipment and system performance, along with analytics and remote monitoring, can improve measurement and verification (M&V) of energy savings in ESCO projects. More accurate information and improved M&V could further facilitate financing of ESCO projects and boost investment in the sector.
Investment in distributed solar PV in the United States was around USD 15 billion in 2018, the second largest market after China and the market has remained one of the most dynamic in terms of installations, despite relatively higher capital costs compared with the global average. In addition to policy support at the federal and state level, the availability of finance has continued to improve, with more players and products entering the market.
While fewer installations are now made by the top developers, payment mechanisms for distributed solar PV in the United States continue to evolve towards increased consumer ownership, compared with entering into leasing arrangements or PPAs with third parties. This reflects the better availability of financing options for consumers and the desire by developers to ease upfront capital expenditures. A number of financial institutions now offer solar loans, which have helped to facilitate direct ownership.
Developers and financing companies are also using the secondary markets to refinance the leases and contracts on their balance sheets as well as their portfolios of solar
loans, which spreads the financing costs and risks among more investors. In 2018, a record amount of asset-backed securities based on US distributed solar PV projects was issued, over USD 2 billion, equal to around 15% of primary financing.
These developments have helped to keep the cost of financing relatively stable. Broadly, the cost of financing for large portfolios of distributed PV projects remained stable in 2018 and was slightly lower compared with two years ago, even as US benchmark interest rates rose, with somewhat more debt used to finance projects and an increased diversity of equity sponsors.
Overall green bond issuance for the energy sector – which acts as an important source of secondary financing in connecting the debt capital markets to companies and projects in energy and other sectors that have environmental benefits – rose to nearly USD 170 billion in 2018.
Growth, at only 3%, slowed significantly compared to the near doubling experienced in 2016 and over 80% growth in 2017, which was boosted by high transaction volumes for mortgage-backed securities arising from the US Federal National Mortgage Association’s Green Rewards programme for energy and water efficiency improvements for multi-family housing in the United States.
Green bond issuance for energy efficiency, which was the leading sector in 2017, declined by 8% in 2018 to just over USD 45 billion. Historically, renewables and mixed- use bonds have dominated green bond issuance in the energy sector. In 2018, mixed-use bonds again captured the largest portion of the market.
Green bond issuance for energy efficiency remained strong in the Asia Pacific region and Europe, while the decline stemmed largely from a decrease in the United States.
In the United States, there was much less issuance based on loans used in property assessed clean energy (PACE) financing, which facilitates the repayment of loans for energy efficiency improvements through property taxes. There was a large decrease in overall PACE applications in 2018 due to the application of new consumer protection laws and the consequent barriers faced by contractors.