There are many potential paths to net zero for European power and gas utilities. In all cases, the technologies that can reduce emissions, and help the utilities reach net zero, require significant investment.

Broad differences in net-zero strategies reflect inherent business mixes and management choices. Company responses to their individual emissions profiles will have an increasing impact on our ratings analysis as we approach 2030.

Here, we outline how we consider the varied factors that impact or are impacted by the transition to net-zero emissions in our analysis.

How We Assess Carbon Emission Trends In Our Credit Analysis

Overall, paths to net zero will be diverse:

• The starting points are companies' business mixes and regulatory constraints. These vary considerably among Europe's energy utilities.
• Utilities face different levels of public commitment, support, and strategies.

Regarding current exposure to emissions reduction, scope 2 emissions typically play a lesser role than scopes 1 and 3. In our analysis, we distinguish between:

• Power generation operations with a significant reliance on fossil fuels, meaning high scope 1 emissions. Reducing such emissions will require significant capital expenditure (capex) in the coming years.
• Natural gas supply, transmission, and distribution operations, meaning higher scope 3 emissions.
• Other energy utility operations, with less emissions altogether, that have more time to reduce scope 3 emissions.

Chart 1

Power generation assets and natural gas supply, face growing risks of substitution by renewables.   Utilities with fossil fuel operations could proactively repurpose some or all of their related assets. For example, coal-fired plants could be converted to run on gas or blue hydrogen, at least during the transition period. Gas grids could be repurposed or expanded to run on hydrogen. This would require regulatory and economic circumstances that are sufficiently supportive, and flexibility to finance the heavy upfront capex at utilities.

Scope 1 emissions have a direct impact on company cash flows.  Carbon dioxide emissions rights prices could rebound toward €100 per metric ton within a few years, according to S&P Global Commodity Insights. Typically, higher carbon dioxide price are passed through to customers for generators. However, high emitting energy sources may lose merit, risking volume and gross earnings decline. Credit mitigants may include activities in other, less-exposed areas; generating significant free cash flow in the near term (as most gas grids have); and restructuring or repurposing operations.

Net zero targets often fail to address scope 3 emissions.   Scopes 1 and 2 emission reduction targets are typically outlined clearly and backed by investment strategies that are sufficiently specific. While almost all energy utilities are focusing first on scopes 1 and 2, scope 3 targets often fail to go beyond the general acceptance of the 2050 carbon neutrality goal. So far, net zero targets have not had much influence on credit quality.

Companies that do commit typically include:

• Greener generators such as Orsted A/S and, since the sale of Uniper SE and assets in Russia, Fortum Oyj .
• Utilities with less polluting gas operations--those with thermal fleets that have plans to abate and no pipelines. For example, Iberdrola S.A. committed to net zero by 2040.
• Those with ambitious green strategies such as Enel SpA, which has a higher scope 3 footprint and is committed to transforming its gas supply business by 2040 and achieving net zero.

Reductions of scope 1 emissions are a key performance indicator of Enel's sustainability-linked financing framework. In 2023, the company was not able to fulfil the conditions under the framework. As a result of missing targets, linked to about €10 billion of sustainability-linked bonds (33% of Enel's total outstanding amount), bonds coupons will be increased by 25bps (about €80 million of additional costs over eight years).

Reduction of downstream scope 3 emissions does not only depend upon the will of utilities.   They are mostly influenced by society and national policies. Companies are therefore typically reluctant to commit to scope 3 targets. Still, we note that Fortum has a much more proximate commitment to neutral scope 3 emissions, it aims to do so already by 2030, than other rated European companies, which look at 2040-2050. At this stage we do not factor in significant downside for the other companies we rate. This is because of a lack of visibility and uncertainty about the pace of emergence of those risks, as shown in chart 1. This is, however, likely over time to be increasingly of importance also for networks. However, as risk becomes more visible, rating impacts may start building up as we gain clarity on company actions or lack thereof. This could be through analysis of businesses, credit metrics, and management.

Understanding emissions profiles can be challenging.   Engie S.A.'s emissions, for example, differ considerably depending on whether one factors equity-accounted investments into scope 3 or not. When we analyze trends in scope 3 emissions, we would typically consider:

• Where the emissions take place (e.g., in jurisdictions with less stringent net-zero policies than in Europe, as is the case for Engie);
• The strategic nature of these operations to the rated parent; and
• The likelihood that the parent's capital providers would challenge its access to capital in case the investees were slow in moving toward net zero.

About 75% of the 20 largest utilities got their net zero or partial reduction targets validated by the Science Based Target Initiative (SBTi), thereby improving the credibility of their commitments through a second, science-based opinion. Some only committed at a general level, without a specified, budgeted increases in capex, which may reflect shallower commitments.

Utilities' Net-Zero Commitments Come With Capex Increases

One of the three key pillars of the REPowerEU plan to end reliance on Russian fossil fuels is to accelerate the decarbonization of power generation. It proposes doing this through massive investment in renewables. Slower-moving utilities will achieve net zero scope 1 and 2 in the 2040s, 15 years or so later than first movers. Through this period, they will face higher capex requirements to change its emission profile.

Despite pressures to meet net-zero targets, we believe few energy companies are ready to add further risk to their balance sheets.   Currently, we have 'bbb' category stand-alone credit profiles (SACP) on most energy companies, including those boosted by regulated operations. We think companies will carefully monitor the risks investments add to their balance sheets. They are likely unready to sacrifice certain credit ratings to meet net-zero goals. In one example of possible risk, on Feb. 7, 2024 we downgraded wind powerhouse Orsted one notch to 'BBB' ('bbb-' SACP) on offshore wind deployment risks, which materialized mostly in the U.S. The profitability of offshore projects profitability should in general justify the risk premium associated with such large-ticket investments, as in oil and gas exploration and production. However, such investments can absorb several quarters or even years of a company's consolidated funds from operations (FFO).

Negative free operating cash flows and, in some cases, deeply negative discretionary cash flows are likely in the coming five years.  Generators with a high share of renewables in their mixes are best placed for growing and strengthening their business positions. Such companies can shift their capex to increasing rather than replacing generation. By contrast, fossil-fuel dependent companies will need to catch up later to meet regulatory requirements. Generators could try to do so by investing in renewable generation or repurposing coal- or gas-fired generation. Power grids, meanwhile, need to bolster grid resilience in the face of more intermittent and distributed generation and rising use of power, which is a consequence of many other industries needing more power to meet their own net zero targets. Gas grids could make efforts to ready their operations to green gases. All face significant execution, regulatory, and cost risks in deploying these strategies.

In 2024 we expect Europe's top 25 utilities to invest some €130 billion equivalent (and limited non-European investments into the European sector) in aggregate. Between 2023 and 2030, the total could reach €1 trillion. In perspective, our very rough approximation is for Europe as a whole to invest some €2 trillion in generation, grids, and batteries by 2030. This would be about double what top-25 rated utilities generate as funds from operations, and also double what they spend altogether annually across their European and non-European business lines. For some individual utilities, this could lead to rating pressure.

Chart 2

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Our high-level forecast, based in part on S&P Global Commodity Insights estimates and excluding LNG and gas-plant related investments and coal closure costs, aggregates:

• Some €0.6 trillion to develop on- and offshore wind generation, respectively, so that Europe contributes a third of the global total of $1.75trillion capex (in real 2022 U.S. dollar terms).
• Some €0.3 trillion in solar generation, benefitting from the latest cuts in module prices.
• Some €0.4 trillion on other generation, including batteries and electrolyzers.
• Some €0.7 trillion on grids, per Eurelectric's approximation of 0.67 spend on grid for each €1 spent on adding renewables generation, given Europe's wind versus solar mix .

This puts into perspective the EU's estimate of the financing it will itself put into place, which under RePowerEU it estimated at some €300bn by 2030. Total capex needs are probably closer to 5x-7x that amount.

Industrial and capital partnerships to share risk could facilitate growth for less-mature technologies.   However, this could lead to group structures, project liabilities, and cash flow circulation that are more complex. Asset rotation is more challenging in industries with more uncertain earnings prospects, especially in a higher-for-longer interest-rate environment. Adaptability, flexibility, and a willingness to change direction will therefore be important in navigating sustained decarbonization paths. This places increasing pressure on management strength, risk management, and other competencies. It also clouds utility sector visibility and credit resilience. We believe the credit profiles of those companies that act now and can maintain competitive production costs will benefit.

Chart 4

Chart 5

Top utilities have already aligned a major share of their investments to the EU Taxonomy.   Some still may raise this share. In 2022 and 2023, most of the utility companies' investments were aligned with the EU Taxonomy. This means they fulfil the Taxonomy's definition by supporting at least one of the environmental targets set by the European Parliament and the EU Council, are aligned with specific screening criteria, and do no significant harm to any of the EU's environmental objectives. At companies such as Orsted, E.ON SE, Fortum, Iberdrola, and Enel, nearly all capex is EU Taxonomy aligned. Other companies, such as Engie and Electricité de France S.A. (EDF) at 66% are close to 75%, but all including CEZ a.s. at 53% post a majority of capex aligned.

We continue to view gas-fired capacity as a bridge technology needed for grid stability as renewables ramp up.   This is mainly because of the conditions attached to gas-fired capacity's inclusion in the Taxonomy (see sidebar above). We incorporate our view of gas-fired capacity into how we assess company business profiles and strategies; we position them as weaker than power grid operators. In addition, we see such capacity as riskier from a stranded-asset risk viewpoint, unless it is hydrogen compatible or combined with carbon capture and storage (CCS) technology. However, both technologies are only moderately mature and not proven at scale. Despite higher carbon emissions prices, it is likely still not economically viable without government subsidies.

Overall, with the increasing push toward investment into sustainable generation technology and smarter, more efficient grids, for both generators and grid operators, we expect to see increasing capex alignment with the Taxonomy.

Chart 6

The Credit Implications Of The Numerous Decarbonization Technologies

We expect Europe's investments in generation to be mostly directed toward wind and solar, and nuclear. In addition, we anticipate investments in gas-fired capacity in Germany and parts of Eastern Europe. Wind and solar are perceived to be the most cost-effective, near-term, and most mature when adding generation capacity. By 2030, the EU is targeting installed solar and wind capacity of 1,236 GW, an upward revision of about 15% from the Fit for 55 plan. That requires a nearly 3.5x increase in the pace of new installations to about 100 GW annually on average. Nuclear is in some countries back into the discussion, despite no recent financial investment decision decisions taken. However, some may come within a few quarters.

Wind and solar technologies, and in some cases nuclear, are the key focus of utility investments.   With these technologies, we focus on net capacity additions and on investment-related risks and their management. However, we note that residential, commercial, and industrial investors are behind a substantial part of the solar capacity being added in Europe. These groups may have other incentives for investment than utilities typically.

Challenges abound on the economics of wind investments, and particularly for offshore.   Utilities, oil companies, and certain projects have seen write-downs, contract cancellation costs, and reprocurement losses related to late commissioning. These losses point to industrywide and company-specific credit concerns. They also explain why since late 2023 certain utilities and oil companies have toned down their renewables deployment plans. All face the adverse combination of higher weighted-average costs of capital as rates rise, reduced rates of returns on renewables investments because of cost inflation, and the heavy constraints posed by supply chains.

The push on wind and solar leaves room for flexible generation for a time.   Such generation could involve hydroelectric power, conventional carbon-intensive technologies such as coal and gas, and to a degree nuclear. Wind and solar intermittency and correlation generate extreme complexities for grids on a spot, intra-day, and seasonal basis. The tension between reliability of generation and the need for stable feed into the grids and to ultimate customers leaves a niche for flexible generation for a number of years.

Nuclear preparing a comeback, but only in certain countries.   Many countries have shut all capacity or are only vaguely considering new nuclear. However, 5 GW of pressurized water reactor design capacity in the U.K. and France over 2024-2030 and 1 GW in Slovakia are under construction.

• EDF probably has the firmest plans for new capacity, with six to 14 new domestic EPRs (10 GW-24 GW) scheduled for commissioning from the latter part of the 2030s. It also plans to extend as much as is technically safe, and at least by a decade, the residual life of its existing fleet of 59 reactors.
• Belgium is extending 2 GW of capacity across two reactors to 2035.
• In Sweden, the government in place since 2022 is more pro-nuclear and has started to change laws, for example on where nuclear plants can be built. It aims to facilitate investment, which still has not been made. Over time though, both small modular reactors (SMRs) and traditional plants are likely, but not before 2035, in our view.
• Poland has plans for up to six new reactors and SMRs, though no final investment decision (FID) has taken place yet.
• The Czech Republic recently upped to four from one the number of reactors it plans to build.

For rated issuers such as EDF, EPH, Fortum, and CEZ, prolonging or in some cases expanding nuclear fleets is key to further decarbonization.   Raising costs, however, remains a consideration. Its relevance depends significantly on the allocation of responsibilities and financing. For example, for CEZ, we expect little impact from costs given arrangements we understand the government is contemplating. Even for the same company impacts may differ, for example for EDF, from very high exposure to rising costs (Flamanville-3 and HPC newbuilds) to much less (Sizewell C).

Emerging technologies will increasingly support decarbonization.   Their credit impact will highly depend on economic models, which are still immature. Batteries, biomethane, and hydrogen are among the technologies that will increase system decarbonization and resilience at the same time. They can help mitigate wind and solar intermittency and seasonality. However, such mitigation would require an aggressive scaling up of such technologies by utilities. From a technological and financial viewpoint, it remains uncertain that this will happen. The fiscal or regulatory support investors in such assets can expect is also unclear.

Chart 7

For alternative solutions, intermittent capacity could be charged a fixed fee to more flexible power technologies that could emerge.   Another option would be for a capacity market to remunerate for capacity that can be activated on short notice. Ultimately, consumers will need to carry the related costs. Furthermore, at a systemwide level, infrastructure needs to be developed at scale, including for transportation and at end-user level. The first steps typically are the most challenging, when a still narrow end-customer base cannot afford to pay for high upfront infrastructure investments.

Chart 8

Many companies discuss CCS projects in their reports, but action is elusive.   Europe has no full-scale CCS projects in operation and only one or two FID have been made, albeit on projects at the planning stage. The rising cost for carbon dioxide may trigger FIDs, however, as capturing and storing carbon dioxide at some point will be economically viable. The technology is critical, both for the utility sector and other industrial sector, to reach net zero. Doubts linger, though, as illustrated by oil companies' challenges even before the latest fall in carbon prices (see "Carbon Capture, Removal, And Credits Pose Challenges For Companies," published June 8, 2023).

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