Germany is accelerating the transformation of its energy mix after the 2021-2023 global energy crisis exposed acute vulnerabilities in its energy supply.

Germany's 2022 energy reform bill, the Easter Package, is the largest revision to the country's energy policy in decades, and centers on a massive expansion in renewable energy. Its ambitious target is to increase the share of renewable energy in Germany's gross electricity consumption to 80% by 2030 from the previous target of 65%. To put these targets in perspective, the share in 2022 was only 47.0% (source: BDEW, the German Association of Energy and Water Industries), although at that stage this represented a record high and was double the share 10 years previously. Even meeting the new target a few years later will constitute a major achievement given Germany's current high-emission status (in 2022, the country's emissions of 230 million tons of carbon dioxide [C02] represented almost a third of the EU's, with C02 intensity the fifth-highest at almost 400 grams of C02 per kilowatt hour [gC02/KWh] versus the EU average of 255gC02/KWh, according to EMBER's European Electricity Review 2023).

Achieving the 80% target will require about €600 billion of investments over 2022-2030, according to the BDEW. Power generators and power transmission and distribution system operators will bear the brunt of these investments. However, in S&P Global Ratings' view, favorable prices for the next few years and lower supply risks will enable currently CO2-heavy power generators to build the financial headroom they need to accelerate a portfolio transformation. The German government may also increase its ownership of certain power transmission system operators (TSOs) to help finance the investments, while incentivizing them through the regulation.

The burden on gas companies is much smaller in the medium term but the long-term strategic challenge is more acute. Germany's target of reaching climate neutrality by 2045 will likely result in decommissioning most networks dedicated to fossil fuel gas. For gas networks to remain relevant, they will need an acceleration of the ramp-up of a hydrogen (and secondarily biomethane) market, coupled with a supportive regulatory framework that balances the risks and rewards of investing in hydrogen infrastructure. The government's national hydrogen strategy provides some hope that this may happen.

All in all, this marks the start of a transformative decade for German utility companies, where risks and rewards are potentially both elevated. A successful portfolio transformation would enhance utilities' long-term sustainability and competitiveness by increasing the share of long-term renewable power generation contracts, reducing the amount of carbon-intensive activities and transforming gas networks.

The Outlook For German Utilities Is Largely Stable As Security-Of-Supply Concerns Ease

We believe that short-term natural gas supply risks are now remote. German suppliers have been and should remain able to source sufficient liquified natural gas imports at acceptable prices for the German and European gas markets to balance. Germany has filled its 250 terawatt hour (TWh) of underground gas storage to a record-high level of 94% of the total capacity as of Sept. 14, 2023, and Title Transfer Facility (TTF) gas prices are trending at €30 per megawatt hour (/MWh) to €35/MWh (in low-to-mid-teens US$/million British thermal units [mmBTu]), down from levels of about €300/MWh at the peak of the energy crisis.

On June 22, 2023, we lowered our forecasts for 2024 Henry Hub and TTF prices in response to lower demand for natural gas and high inventory levels (see table 1 and "S&P Global Ratings Lowers Hydrocarbon Price Assumptions On Moderate Demand," published June 22, 2023). These additions will only gradually enable TTF and Henry Hub to partly converge, also reducing the power-price divergence between the U.S. and Europe.

Table 1 

Reflecting this stabilization in prices, albeit at a somewhat elevated level (2x-3x levels prevailing in mid-2021), and just a few quarters on from the turmoil in the European gas and power markets over the summer and autumn of 2022, 87.5% of our ratings on German utilities have stable outlooks, up from 75.0% as of Sept. 30, 2022. Notably, on June 19, 2023, we revised the outlook to stable on Uniper SE, as the company mitigated its financial exposure to gas stoppages and started to recover financially after hedging the volumes it sold before Gazprom interrupted its contractually agreed gas supply (see "Uniper Outlook Revised To Stable On Return To Profitability; ‘BBB-' Rating Affirmed," published June 19, 2023).

Earlier in the year, we also revised the outlook on EnBW Energie Baden-Württemberg AG (EnBW) to stable from negative to reflect the end of its exposure to Russian gas as of 2023 and locked-in margins at its power generation and trading business, which more than compensate for losses at its subsidiary VNG AG in 2022 (see "EnBW Outlook Revised To Stable On Improved Credit Metrics Trajectory; 'A-/A-2' Ratings Affirmed," published March 30, 2023).

We also have a stable outlook on Energeticky a prumyslovy holding (EPH), which we first rated on Aug. 29, 2023 (see "Czech-Based Energy Company EPH Assigned 'BBB-' Rating; Outlook Stable," published Aug. 29, 2023).

We Expect Investments In Power Grids To Accelerate, And Those In Gas Grids To Plateau

The Easter Package will boost investments in both high- and low-voltage grid deployment. The BDEW and consultancy firm EY recently released a progress monitor for the energy transition, estimating that about €600 billion of investments are required over 2022-2030 in Germany to reach the 2030 targets. Of this figure, 21% corresponds to electricity grids, or about €15 billion annually, and only 3% to natural gas and hydrogen networks, or about €4 billion annually (see chart 3).

Similarly, the most conservative of the three scenarios under the June 2023 draft of the German Network Development Plan (Netzenwicklungsplan, or NEP), which envisages 1,050 TWh of power demand in 2045, incorporates €183 billion in investments just for TSOs to expand their onshore and offshore grids until 2037. This is almost twice as much as under the previous NEP that ran to 2035. In contrast, the proposed NEP for gas only entails €4.4 billion from 2022 to 2032.

In our opinion, this divergence reflects the fact that the energy transition has much stronger stimuli for power grid operators than for gas grid operators, which face adverse demand dynamics for fossil-gas and technological uncertainties in adapting their networks to hydrogen. Timelines also differ; while power grids face immediate capex hikes, demand for fossil-gas transportation will mostly decrease after 2030 (see chart 1), buying the gas grids more time to set up their strategies and balance sheets accordingly.

Chart 1

Investments in the power transmission grid from 2023 to 2037 equate to nearly twice the pace anticipated just two years before, indicating the transformative nature of the upcoming development. For offshore, the challenge is to multiply the generating capacity connected to the land grid by 7.5x by 2037 and 9.0x by 2045; this requires investments about 8x bigger than the €12.4 billion currently underway, according to the NEP. Offshore investments tend to rely preponderantly on TenneT Holding B.V. (TenneT), and then on Eurogrid. S&P Global Commodity Insights' base case envisages slightly less renewable capacity expansion, resulting in 10%-15% less solar and wind capacity for 2037 than the NEP forecasts and about 900 TwH of demand in 2045. Yet the magnitude of the necessary buildup remains high.

From a credit perspective, both the electricity and gas grids are protected by what we assess as a strong regulatory framework, the most credit supportive of five categories (see chart 2). However, we believe that gas grids carry significantly more risk than the power grids over the longer term. In some cases, we reflect this in slightly more demanding triggers for the same level of rating to the degree we perceive that this increased risk dilutes the strength of the gas grid operators' businesses.

Chart 2

The challenge for the power TSOs is how to finance several years of very heavy capex with leveraged balance sheets and before the new assets generate earnings. To put aggregate power grid capex needs into perspective, investing €14 billion-€15 billion annually over 2024-2037, as per the BDEW or NEP estimates, equates to about three times the pace of investments in 2022. This assumes a significant ramp-up in execution and requires financing to be in place before the TSOs' earnings start benefiting from the new investments, which are amortized over the very long term. Thus, the next decade is crucial. After that, capex needs will drop to about €5 billion per year over 2037-2045, one-third of their level in 2024-2037, according to the NEP.

A further feature of power TSOs' capex needs is that, as per the NEP, a slight majority up to 2037--and nearly all the capex after 2037 --would relate to lines connecting wind offshore projects, and thus fall on only some of the TSOs. This is despite just over 40% of the new lines being offshore (by kilometer length), highlighting how costly end-to-end offshore development is. We also think that offshore wind is most exposed to specific cost inflation in the renewable capacity buildout.

Chart 3

Balance Sheet Headroom To Accelerate Grid Investments Varies Among Operators

We believe that most grid operators carry significant leverage, although some, such as E.ON SE, have sufficient headroom to accelerate capex. We forecast funds from operations (FFO) to debt of 15%-16% for E.ON in 2023, versus a minimum expectation of 12% for the 'BBB' rating. In its 2023-2027 strategic plan, E.ON focuses on expanding its regulatory asset base (RAB) from about €36 billion as of Dec. 31, 2022, to more than €46 billion by 2027, along with its customer solutions business. We note that these RAB projections exclude additional investments related to the Eastern Package, which is why we believe there is upside to E.ON's capex (see "E.ON SE," published on July 14, 2023).

We understand that E.ON would be responsible for connecting a material share of the onshore wind farms and new PV capacity planned under the Easter Package until 2030 to its medium-voltage grid. We believe this will solidify E.ON's position as one of the strongest network companies in Europe from a business perspective. This view led us, on May 11, 2023, to lower our upper expectation, at the 'BBB' rating, for E.ON's FFO to debt to 14% from 15% previously.

Increased Government Participation Is One Of The Options To Share The Load

We see the German government's increasing presence in the energy industry as a shareholder in power TSOs as a salient development that may facilitate the financing and execution of the massive investments needed. The government's presence, so far limited to its development bank KfW's 20% ownership of the 50 Herz grid (a subsidiary owned by Eurogrid GmbH, rated 'BBB+/Stable'), could at some point include up to 24.95% of TransnetBW and up to 100% of TenneT's German operations. Thus, the government would be present in all but one of the four TSOs.

Indeed, to fund its domestic growth, which it estimates necessitates €10 billion additional equity through 2030, Netherlands-based TenneT seeks to divest 100% of its German operations to the German government, which it estimates necessitates another €15 billion. This could prove transformative for Germany's TSO landscape since TenneT's operations are the largest in the country. TenneT is a key player in the high-voltage transmission projects Südlink and SüdOstLink, each with 4 GW of capacity, which will transport electricity between the North of Germany and the power-hungry South by 2028. Also, TenneT's operations cover most of Germany's offshore domain in both the North and Baltic seas, the costly development of which is key to raise Germany's total wind generation.

EnBW disposed of 24.95% of the shared capital at its power TSO subsidiary TransnetBW (unrated) to a consortium of more than 30 German banks on May 26, 2023. It is still in talks for KfW to exercise its 24.95% call option on TransnetBW shares, which we understand could happen this year. We already account for government support in our rating on EnBW through its 46.75% ownership by the State of Baden Württemberg (AA+/Stable/A-1+). As such, the central government's potential acquisition of a minority stake in TransnetBW through KfW is unlikely to affect our ratings on EnBW.

We Expect The Regulation To Adapt To Incentivize Investments

Just as power grid operators must boost investments to meet renewable energy targets, cost inflation and the cost of funding are increasing materially, with high interest rates not set to abate in the near term.

The German regulatory framework, like many others in Europe, was designed to remunerate regulated infrastructure in periods of relatively constant investments. Consequently, returns on the RAB are typically spread over a long depreciation period, and under the German regulatory formula, usually lag market conditions. The investment supercycle could therefore strain operators' balance sheets and dilute credit quality.

To address this possibility, the German regulator, Bundesnetzagentur (BNetzA), proposed to update the revenue cap for new investments every year, instead of waiting up to five years (that is, until the end of each regulatory period), thereby reducing the time lag in operators receiving returns on new investments. Equally crucial, on June 7, 2023, BNetzA also proposed to raise to 7.09% from 5.07% the allowed pretax return on equity on power grids' new investments over the fourth regulatory period (excluding investment measure investments [IMAs] and existing investments), with the figure being adjusted on the actual level annually. If maintained, we expect the impact of this proposal would be modest at first and could increase only as new investments are incorporated into RAB, provided that the variable rate of return remains high. However, overall, we view this as credit supportive for applicable investments, as well as for the sector in general.

The final parameters, if set at these proposed levels, could partially mitigate the current adverse macroeconomic conditions. We will assess the impact of the proposals on our rated issuers' credit quality once they are finalized, which we expect will happen before year-end 2023.

Favorable Prices Allow Power Generators To Build The Financial Headroom To Transform Their Asset Portfolios

EnBW, Uniper, EPH, and RWE, along with other power generators operating in Germany are currently benefiting from the still-high power prices and sustained gas prices relative to historical levels. We expect sustained EBITDA until 2025, before lower prices erode it (see chart 4).

For now, we observe German utilities using their increasing financial headroom to accelerate the transformation of their asset portfolios. In this context, capital allocation will be crucial in determining the strength of their future business risk profiles. For leveraged companies facing high capital expenditure (capex), we expect the moderation in shareholder payout rates to continue.

Chart 4

We expect that EnBW will invest about €3.8 billion in 2023 and €5.0 billion in 2024--considerably more than €2.1 billion-€2.7 billion until 2022--as it dedicates almost half to regulated grids and close to 30% to renewable power generation. EnBW also intends to switch its coal power plants to new power combined cycle gas turbine (CCGT) plants. These CCGT plants would also be compatible with renewable gases once a supply chain to Southern Germany allows for this. We believe that this strategy will enable EnBW to preserve a flexible generation portfolio that complements its increasing renewable capacity, which we view as a likely competitive advantage in the long term.

Uniper also recently announced its ambitions to invest about €8 billion until 2030 in transforming its asset portfolio, aiming to grow in wind and solar. It aims to increase its capacity for renewables and low-carbon gases to more than 80% of its total capacity from 20% today while slightly reducing its total installed capacity of 22.5 gigawatts (GW) to 15 GW-20 GW.

For EPH, the transition is likely to be more challenging and there is no public commitment yet to shut down coal in Germany before the official 2038 target. LEAG (50% owned until 2025 by EPH) plans to invest in the transition from coal and lignite to renewable and alternative low carbon sources. The investment plan to decarbonize amounts to €10 billion by 2030 focused on the development of renewable energy sources, batteries, and hydrogen-ready power plants. However, we view significant execution risks attached to this transition plan given the share of coal and lignite generation to phase out and replace.

Overall, We See A Positive Balance Of Risks For Utilities' Investments In Renewable Capacity

This reflects our understanding that utilities' renewable investments are typically engaged in credit-supportive contracts signed early on (for example, at or around the final investment decision), such as those long-term power purchase agreements that make cash flow generation more predictable than if such capacity is fully merchant, that is, exposed to market fluctuations. Furthermore, the greening effect is particularly strong for German power generators, which have the largest carbon footprint among rated Western European utilities, as their plants still generate significant power from coal and lignite (see chart 5). Finally, for the biggest projects we typically assess positively the sharing of risks as utilities tend to seek co-financiers, as demonstrated by EnBW's 49% farm-down of its approximately €2.4 billion He Dreiht offshore wind project.

Chart 5

German coal power operators must also retain a relevant share of their existing coal capacity for security-of-supply purposes. This is particularly true of EnBW, most of whose installed coal capacity is in Southern Germany, supplying the energy-hungry states of Baden-Württemberg and Bavaria. Notwithstanding this, most German carbon-intensive power generators have a clear exit path from coal well ahead of the 2038 legal deadline, for instance, EnBW by 2028, RWE by 2030, and Uniper by 2029. One exception at this stage is EPH's subsidiary LEAG, which targets the last closure by 2038, the legal deadline. Despite these plans, we believe that the pace of the coal phase-out depends on Germany achieving its renewable energy targets and successfully deploying necessary grids to absorb the increased capacity because of security-of-supply concerns.

We think that coal generation, while currently very profitable, weakens a power generator's business risk profile given the long-term need to shut down the assets and because of margin risk on CO2 emission allowance prices. Therefore, specific and well-funded plans to accelerate coal's replacement with new gas-peaking or renewable capacity tend to support business risk profiles. Renewables also carry significant risks (see "EU's Proposed Energy Market Redesign Mitigates Merchant Risks And Accelerates Renewables," published on April 3, 2023, and "Europe's Utilities Face A Power Price Cliff From 2026," published on June 22, 2023). In our view, the combination of non-dispatchable renewable generation with CCGTs greatly strengthens operators' profitability profiles. This is because they will be able to produce baseload at lower marginal costs while preserving the flexibility to dispatch electricity at peak hours, thereby benefiting from higher spreads and ensuring security of supply. We understand that all new CCGT plants will be ready to take renewable gas or hydrogen by the end of the decade.

We acknowledge that, for integrated players, trading activities provide a competitive advantage through arbitrages between commodity prices on the procurement side (sourcing their energy needs) and power and gas prices on the supply side (selling to their customers). Indeed, we have recently observed a significant increase in trading-related cash flows. However, we view commodity trading as inherently more volatile and riskier than contracted renewable generation, and difficult to monitor. This is why we assess these cash flows as less leverageable than contracted renewable generation, or regulated activities.

We expect that dispatchable coal and gas capacity will remain profitable as renewable generation capacity continues to ramp up, and as Germany shut down its last 4 GW of nuclear capacity on April 15, 2023. Germany became a net importer of electricity in May and June 2023, and this trend could continue, depending on the relative paces of electrification of demand against renewable deployment; overall we expect Germany to become a significant importer later this decade (see chart 6).

Chart 6

Germany Is Progressing Steadily Toward Its Ambitious Energy Targets

Germany's Easter Package raised the targets for onshore wind capacity to 115 GW by 2030 (from 59 GW today), for offshore wind capacity to 30 GW (from 8.4 GW), and for solar photovoltaic (PV) to 215 GW (from 74 GW; see chart 7). The government recently passed the Renewable Energy Sources Act (EEG) 2023, complementing it with the Offshore and Onshore Wind Energy Acts, to streamline the permitting process for new renewable capacity, a major stumbling block for deployment.

For instance, in the EEG 2023, Germany established that the deployment of renewable energy is of common interest and a matter of national security. This should allow its deployment to take priority over matters that slowed it in the past, such as the protection of endemic species. Through this legislation, the government will offer about 22.8 GW for tender of offshore wind capacity by 2027. It has also ruled that 1.7% of the land surface of each German state should be allocated to onshore wind farms by 2027, and 2.0% by 2032. The government also raised the fixed remuneration for all solar capacity put in operation from July 30, 2022.

Chart 7

We believe that these measures will accelerate the pace of renewable energy deployment in Germany, and we observe that approvals are gaining traction as of the first half of 2023. However, the pace of deploying new capacity is ambitious, for onshore wind at three times the average pace from 2010 to 2021, and more than four times for solar.

In parallel, power grid infrastructure and battery capacity will also have to be deployed and adapted to an increasingly complex and decentralized power generation mix, making the achievement of the targets even harder.

We believe that capital flows currently strongly favor renewable power generating assets, provided the economics are right. However, the rollout of necessary grid infrastructure to connect all new capacity, which is subject to technical and permitting constraints, and also requires massive funding. This partially explains the likely increased presence of the German government in grid operators, such as TenneT and Transnet BW. All in all, the commissioning of new renewable projects could be compromised if transmission and distribution grids are not deployed at the required pace, on top of impeding the now accelerated phase-out of coal and lignite power generation.

Germany's NEP sees a massive rise in battery storage capacity to 91 GW by 2037 (of which 24 GW are utility scale) and 141 GW by 2045, from just 1.8 GW in 2021. Certain NEP scenarios also expect significant imports to be available from France, Austria, and Scandinavia, which in turns assumes oversupply in these markets.

The Acceleration Of The Energy Transformation Brings Execution Risks

Across Europe, the 300 basis point increase in risk-free rates since December 2021, along with high inflation on the unit costs of renewables investments, are reducing the profitability of new renewable power generation projects. This is particularly the case for offshore wind projects that are subject to contracts with prices that were fixed in a more benign cost and financing environment.

These challenges could affect utilities developing new offshore wind capacity, such as Danish offshore wind market leader Orsted A/S, Vattenfall AB, and EnBW, among others, as well as power TSOs. Vattenfall recently announced that it is stopping the development of the 1.4 GW offshore wind park Norfolk Boreas in the (English) North Sea due to rising costs and supply chain constraints. In addition, according to the International Energy Agency, the levelized cost of electricity for onshore wind and utility-scale solar PV projects should remain 15%-20% above 2020 levels by 2024, despite improvements in technology.

If industry risks increase materially, this could lead us to revise our rating thresholds for issuers most exposed to offshore wind companies. For example, on July 13, 2023, we raised our minimum FFO to debt expectation on Orsted at the 'BBB+' rating level following, notably, impairments on wind projects, highlighting rising industry risk.

We therefore think that good supply chain management and tight execution will become an increasingly relevant competitive advantage. Such management could include the ability to procure sufficient components and fix their costs before the final investment decision is taken, or close contracts that adapt to the increasing cost environment.

Offshore Wind Deployment Is Gaining Momentum In Germany Despite Supply Chain Challenges

The deployment of new offshore wind capacity in Germany is gaining traction, as evident from the recent negative bids for the four sea surface areas that the government tendered at the beginning of the year. Negative bids mean that project developers pay the government to be able to build a wind farm. The total output potential for these tenders is up to 7 GW in the North and Baltic Seas. BP PLC and TotalEnergies SE bid a massive €12.6 billion to the German government as seabed lease payments, of which 10% are unconditional and to be paid upfront. This translates into a lease payment of about €22/MWh by our estimates. The German government also awarded 1.8 GW of potential capacity to RWE, Vattenfall, and Waterkant Energie in August 2023 for a lease payment of about €6/MWh by our estimates.

The considerable difference between the implicit negative bids of BP and Total and those of RWE, Vattenfall, and Waterkant exemplifies in our view the oil majors' ability and willingness to pay a high price to enter the German electricity market. It also suggests that German utilities will be subject to increased competition in future, likely at the expense of profitability. The next tenders will be mostly subject to a so-called beauty contest, whereby not all of the auction criteria is standardized, and the winning auction is the one closest to a function of all submitted bids. They are scheduled in 2024 for total capacity of 8 GW, followed by about 6 GW between 2025 and 2027 (see chart 8).

Chart 8

Under the German tender system approved as part of the updated Offshore Wind Energy Act, capacity will be distributed by means of two different bidding processes. The auction will take the form of a beauty contest for sites the BNetzA has already investigated and, for others, of a one-sided contract-for-difference price bid and prequalification criteria. The latter could turn into a dynamic bidding process in the event of bids of €0, whereby bidders with the highest willingness to pay are awarded the contract.

Both bidding processes are subject to uncapped negative bidding and are fully merchant. For utilities, this means ongoing contracting risks unless sufficiently protective power purchase agreements are put in place.

As Renewable Capacity Ramps Up, We Expect The Profitability Of Dispatchable CCGT Plants To Decline

We believe that backup CCGTs' flexible-generation capacity will remain critical throughout Germany's energy transition, absent nuclear capacity and given government plans to phase out all of the 18.9 GW of coal and 18.5 GW of lignite capacity by 2030, except in Eastern Germany. Yet, as more renewables are added to the baseload to achieve 70%-80% of total generation by 2030, we believe that the load factors of CCGT plants will decline.

We therefore think that a non-wholesale market revenue mechanism, that is, capacity support, will be essential for newbuild CCGT plants, and that it will be increasingly necessary to keep existing capacity online, or transform them into environmentally friendly gases.

For instance, on Aug. 1, 2023, the Ministry of Economics and Climate Protection (BMWK) published a preliminary framework for its national power plant strategy, which is likely to influence the transition of thermal power generation in Germany, including the intention to accelerate the deployment of hydrogen-ready power plants. We understand that the government intends to tender about 10 GW of new (6 GW) and converted CCGT (4 GW) plants by 2026, and that such assets would likely benefit from some form of capacity subsidy. Also, this initiative includes 4.4 GW of power plants that generate electricity from renewable hydrogen (so-called sprinter power plants), and 4.4 GW hybrid power plants, including integrated electrolyzers and storage. We understand, however, that this is still subject to consultation in the last quarter of 2023, and must still go through European Commission approval.

Utilities' Trading Risks Are Diminishing Thanks To Gas Market Stabilization And Portfolio Rebalancing

Utilities trading-related liquidity needs have sharply retreated from extremely high levels from late 2021 until early 2023. These were mostly due to the difference between the price at which they closed the delivery contract for a specific commodity, such as power or gas, and the actual price during the energy squeeze in Europe, which the Russia-Ukraine war aggravated in 2022. As the actual prices catch up with the contract prices, the difference between these two variables should reduce the amount of margin collateral that utilities post.

In addition, the availability of (notably U.S.) liquefied natural gas, along with continued demand moderation (about a fifth down over two years) in European, and notably German, gas demand have enabled European gas prices to ease to levels between €30/MWh and €35/MWh. Most utilities have also bolstered their liquidity lines and we assess liquidity as adequate or better for all rated ones.

Finally, we see a shift to transfer trading risk to bilateral counterparties (OTC) from exchanges which, positively, reduces initial margin calls but, negatively, increases counterparty risk. Thus, while we believe that the gas and power markets will remain volatile overall, we think that the sector is better prepared for a liquidity shock.

The Russian Gas Phase-Out Forces Importers To Rethink Their Contract Structures

The loss of all German pipeline gas imports from Russia, which were, to a large extent, under long-term contracts, forced importers to procure gas from alternative sources, including the spot market, at way-higher prices. We see clear signals of a gradual, but steady, decline in fossil-gas demand in Germany (see chart 1). Germany has set itself a legal climate neutrality target date of 2045, which we estimate could reduce national gas demand by 76% by then.

In addition, the government recently introduced legislation (Anpassung von kalkulatorischen Nutzungsdauern von Erdgasleitungsinfrastruktur; KANU) that allows gas operators to fully depreciate by 2045 their gas infrastructure commissioned after 2023, shortening the depreciation time from the industry standard of up to 40 years. This accelerates cash inflows at the expense of longer-term prospects, so we will monitor the extent to which, if any, such upfront cashflows are upstreamed to shareholders versus invested or applied to reduce debt. The government also introduced contracts aimed at compensating companies for additional costs when they switch to more climate-friendly production processes, for example those using hydrogen.

Furthermore, as of July 2023, only about 12.5% of new residential constructions have gas central heating, versus 52% built with an electrical heat pump (see chart 9). This contrasts with the national share of 49% of residential buildings using gas as primary source for heat. We expect that this trend will accelerate as the German government provides incentives to reduce fossil fuel-based heating.

Chart 9

As the decline of fossil-gas demand in Germany intensifies, and after the 2022 energy crisis awakened supply concerns, we expect that gas consumers will change their consumption patterns, particularly industrial consumers. This will ultimately require more flexibility from gas suppliers. Gas importers such as Uniper or EnBW's VNG will face a trade-off between long-term contracting to secure volumes at lower prices, making themselves dependent on fluctuations in gas demand, or shorter-term contracting that may dampen margins but reduce long-term exposure to demand fluctuations. Either way, short- or long-term gas imbalances will remain relevant credit considerations, and we expect issuers with less exposure to volume and price fluctuations to be better off.

Gas Grid Operators Rely On Favorable Regulatory Developments For Hydrogen

In contrast to the electricity grids, we see investments plateauing for gas networks over the next few years, with some growth for the transmission grids versus almost purely maintenance capex for the distribution grids.

Germany's target of reaching climate neutrality by 2045 will likely translate into a sharp decline in the use of gas, with only residual demand remaining by then. On Nov. 8, 2022, BnetzA issued a new calculation method to remunerate new investments on gas networks, which allows operators to wholly amortize such investments in a linear fashion until 2045. This essentially removes the risk of stranded gas grid assets because it guarantees that new investments will have been remunerated by 2045 at the latest. However, we expect that investments will gradually dwindle to become maintenance-only, reflecting the grids' increasing maturity.

However, stranded-asset risk remains for gas grids already in place before 2023 with a useful life that runs beyond 2045, because we understand that the new methodology excludes them. This means that Germany still requires a solution for such assets, particularly as demand declines and fewer customers need to share the tariff burden.

Furthermore, gas transmission operators such as Open Grid Europe (VGT's subsidiary), ONTRAS (EnBW's subsidiary), and Gasunie Deutschland (N.V. Nederlandse Gasunie's subsidiary), whose sole exposure is to gas transmission infrastructure, risk a progressive waning of their businesses. Their long-term relevance partly depends on the development of a regulatory framework for hydrogen that enables them to invest in such infrastructure.

The Development Of Hydrogen Infrastructure Could Gather Pace Quickly

On July 26, 2023, the German government updated its national hydrogen strategy, including a goal to speed up the development of a hydrogen market. This plan increased the target for electrolyzer capacity to 10 GW by 2030 from 5 GW before. Electrolyzers produce hydrogen by splitting water into hydrogen and oxygen. The plan aims to incentivize the industrial use of the fuel through carbon contracts for difference, while assuming demand of 95 TWh-130 TWh by 2030. The European hydrogen backbone network of energy firms participating in a low-carbon hydrogen market will be a key component of the future hydrogen supply chain.

Against this backdrop, Germany's gas transmission system operators have submitted to BNetzA a plan to deploy a hydrogen network consisting of 11,200 kilometers of pipelines, of which around 60% will be repurposed gas networks and the rest new infrastructure. We estimate that the cost of such infrastructure will range between €15 billion and €20 billion, depending on the final length of the pipelines, which according to BNetzA, can still be optimized. BNetzA still needs to finalize and approve the plan, but in our view, it shows that the deployment of hydrogen infrastructure is gaining traction in Germany; reducing long-term business uncertainty would, in our view, be credit-positive for gas TSOs.

We expect BNetzA to finalize the plan in the short term, and to develop a regulatory framework incentivizing investments in hydrogen infrastructure, since the government intends to seek private financing for them. However, we expect that hydrogen infrastructure will require direct support during the ramp-up phase since we expect the number of hydrogen offtakers to increase only modestly at first, making fee-based remuneration inviable in the short-to-medium term.

Conclusion

The German Energy Transition will be transformative for German utilities' businesses. We believe that its acceleration will bring short-term operational challenges, such as managing the pace of a power generation portfolio transformation against ambitious timelines and targets, coupled with the need to fund and build a power grid that can absorb the increasing decentralized generation. For power TSOs, the challenge is that the pace of investment requires them to finance investments three times larger with cash flows that will only gradually contribute to earnings. This is also a challenge at the distribution level. We nevertheless think that power generators will have a more sustainable and profitable business mix after emerging from this transformation. We also anticipate that investments in power grids will provide an asset base that will grant a stable and predictable source of cash flows over the very long term, thereby solidifying their position as critical infrastructure.

We believe there are more uncertainties for gas grids beyond the next two decades. For instance, by 2045, we expect that most, if not all of the existing gas infrastructure will be depreciated, and it is currently unclear what share of the existing gas infrastructure will remain in use thereafter. Additionally, some residual stranded asset risk remains for infrastructure not covered by the KANU legislation. However, we recognize that there will likely be opportunities to adapt existing gas grids and deploy new infrastructure to develop a hydrogen backbone, which is a priority for the German government and more broadly a key EU goal. This could answer the existing questions about the future of gas grids in Germany, but the robustness of such prospects relies heavily on the hydrogen market gaining traction over the medium term, on imports being available, and on a supportive regulatory framework.

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