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The Path To Germany's Coal Exit Has Diverging Credit Implications For Utilities

(Editor's Note: On Nov. 17, 2020, we corrected this report to update incorrect information in chart 7 and a sentence referencing it in the text.)

Germany's decarbonization goals are a formidable challenge for the utilities sector given that coal and lignite still represented close to 30% of the country's power generation as of 2019 and 20% as of June 30, 2020. Yet, the government has now clarified its coal and lignite orderly exit process, with action starting this year. Adding to complexities for utilities, the decarbonization plan is running in parallel with Germany's nuclear exit program, to be completed by 2023, leading to an unprecedented shift in energy sources.

From our reading of the plan, lignite-fired plant owners are generally better compensated than coal generators, likely owing to lignite's higher profitability and hence better position in the merit order. Overall, though, this exit plan has the merit of offering a rapid, and eventually economically viable incentive for operators to swiftly decarbonize their power generation portfolio, reduce their social risk exposure, and cover for their asset retirement obligations. While still too early to say, we see further upside stemming from the conversion of their industrial sites, which could turn out to provide additional value over time.

The Agreement Marks A Major Step Forward For The Future Of Coal And Lignite

In July 2020, the German parliament approved a law that establishes that power generation from coal will stop no later than 2038, but potentially already in 2035, depending on feasibility revisions against the country's security of supply considerations scheduled in 2026, 2029, and 2032. This law puts an end to a decade of complex discussions by multiple stakeholders to create a plan to phase out coal, aiming at providing a smooth structural change to Europe's largest economy energy mix. With this plan, Germany intends to reduce its close to 21 gigawatts (GW) of hard coal capacity and 18 GW of lignite capacity to 15 GW each by the end of 2022, and 8 GW and 9 GW, respectively, by 2030 (see chart 1).

Chart 1


The coal exit will be largely achieved through tenders over 2020-2026

To achieve this goal, the German Federal Network Agency (BNetzA) will organize a series of auctions in which coal plant operators can bid in order to receive compensation for immediately shutting down their capacity. Compensation will decline in later tenders, so as to incentivize operators to participate at an early stage in the process. The mechanism aims to compensate the lowest bids based on CO2 emissions avoided. However, since coal capacity will be phased out by means of a tendering process, the pace and capacity of the phase-out depends on participants. The first auction, which targets taking 4 GW offline, concluded in September 2020. The results of the tender process will be announced in December this year, and operators with winning bids will have to take down their capacity from the wholesale market before January 2021 and stop generating power at these sites by July 2021. The subsequent series of auctions will take place in 2021, aiming to have enough bids to reach the 2022 target of having a maximum of 15 GW of hard coal capacity in operation, followed by yearly auctions running until 2027 (see table 1). After 2027, we expect the German government to mandate closures with no compensation payments, starting with plants that are the least efficient and produce the most greenhouse emissions, and depending on grid stability criteria, which would most likely exclude power plants in the southern region of Germany.

Table 1

BNetzA Coal Auctions
2020 2021 I 2021 II 2021 III 2022 2023 2024
Remuneration per GW 165 155 155 116 107 98 89
Maximum capacity being shutdown (GW) 4 1.5 x-15 Capacity to be taken offline by 2023 Capacity to be taken offline 2024-2027
GW--Gigawatt. x = outstanding capacity above target of 15 GW.
Lignite has a clearer exit path, benefiting RWE and EPH the most

Lignite will follow a predetermined schedule, and relevant operators will receive compensation totaling €4.35 billion. Lignite will receive higher compensation in nominal terms than coal. In addition, the lignite compensation is already allocated to the two lignite plant operators: €2.6 billion will go to RWE for its 10 GW capacity, and €1.75 billion to LEAG, owned by Czech EPH, for its 6.6 GW capacity. This implies a €260 million-€280 million compensation per GW, which we view as more favorable than the current economic outlook would suggest. That said, we acknowledge lignite generation has a better position in the merit order of the German price zone (lower variable cost) and hence typically higher profitability than hard coal generation.

Further, the region and workforce of RWE and EPH's lignite mining and generation activities in Germany will benefit from state funds mitigating the social impact and cost affiliated with lignite phase out as a whole.

Beyond mandatory shutdowns, economics for coal and lignite are poor

On top of the political willingness to reduce the energy sector's carbon footprint, profitability of coal and lignite plants has declined considerably in recent years, and there is limited hope for upside in the coming decade. Coal and lignite plants have been mostly unprofitable over the past 2-3 years, as carbon dioxide (CO2) allowance prices have continued to increase and gas prices declined to historical lows, which has pushed coal out of the merit order at times (see chart 2). This effect has been further exacerbated by an increasing share of intermittent generation (renewables) and--at least temporarily--a decline in power demand due to the COVID-19 pandemic shock. We believe that the trends leading to increasingly unfavorable economics for coal generation are likely to continue. One reason for this is reduced supply of European emission allowances (EUA) via the market stability reserve. In our opinion, this means that the market condition itself could have gradually resulted in the shutdown of these plants, although some sooner than others depending on their individual efficiency, profitability, and contract profile. In fact, in 2020, Vattenfall wrote down €890 million of its 1.7 GW Hamburg Moorburg hard coal plant, only commissioned in 2015, in addition to other writedowns to this and other coal assets since 2010. This is just one example among several conventional generation asset impairments over the 2015-2020 period for the coal generation industry.

Chart 2


Coal assets are on an unfavorable profit trajectory

Coal generation was the sharpest declining form of conventional power generation since 2016 (see chart 3), signaling that these assets are already in an unfavorable profitability trend. In our opinion, the coal phase-out is slightly favorable for hard coal operators, which can participate in the auction mechanism. Coal plants inherently face shutdown costs such as asset retirement obligations (AROs) and personnel expenses, which may vary depending on the asset. We understand that the German law requires operators to remove hazardous waste from the site but not to return the sites to a greenfield status after decommissioning, which significantly reduces decommissioning costs. We estimate that AROs per GW of installed coal capacity range from €5 million-€70 million, depending on the asset, which means that most operators should be able to cover for these costs using proceeds from the auction mechanism. Operators would have had to cover for these costs with or without compensation. Because these assets were unlikely to get back to profit in the medium to long term, we believe that the auction mechanism leaves operators better off than a status quo scenario; more so if the assets are exposed to merchant generation.

Chart 3


The coal exit may result in some upside for gas generators

Because of the currently unfavorable operating environment for hard coal generators, the German coal phase-out provides operators with incentives to participate in the BNetzA auctions at the earlier phases (before 2027). In our opinion, the coal phase-out, coupled with the already scheduled nuclear shutdown, could increase load factors for gas generators, which could play a relevant role as Germany's installed capacity declines over the coming decade. To mitigate the country's looming dependency on imports and to be able to ensure sufficient security of supply, the German government has the option of following the coal commission's recommendation to introduce a risk-oriented monitoring of supply security, potentially by facilitating the expansion of gas-fired generation. As such, we expect incentives to be introduced for highly efficient combined cycle gas turbines (CCGTs), as well as for gas-fired combined heat and power (CHP) generators in the medium term (for further details see "The Energy Transition And What It Means For European Power Prices And Producers: Midyear 2020 Update," published June 8, 2020, on RatingsDirect).

In addition, given the industrial real estate scarcities in Europe, and Germany specifically, we believe that the coal exit could provide brownfield opportunities for our rated issuers, converting coal plant sites to greener usage, such as efficient gas plants, waste incineration, commercial scale storage solutions, data centers, biomass, or other renewable generation. Such projects face lower permit hurdles and limited public opposition. We currently don't capture any upside in our ratings, as it is still too early to assess any considerable opportunity, but we recognize that utilities could find some hidden value, which would support debt reduction and investment funding over time.

A shorter-term use of these assets could be to convert them to gas or environmentally friendlier fuels. In addition, the approved legislation provides incentives for converting a coal CHP plant to waste, waste heat, biomass, or gas, receiving financial compensation ranging between €5 million an €390 million per GW of installed capacity (the so-called Coal Replacement Bonus).

However, even though prospects of gas generation as an important role in guaranteeing security of supply as base load capacity phases out, the longer-term prospects are not favorable because of the European taxonomy, and depend highly on the emergence of new technologies, such as storage solutions or power-to-x.

Chart 4


Which Rated Issuers Are More Exposed To The Coal Phase-Out

Among our rated issuers, Uniper, EnBW, Vattenfall, and EVN own and operate hard coal power generation assets in Germany and, together, these companies represent about 58% of the total installed hard coal capacity in the country. In our business risk assessment, we consider coal generation as negative because these assets face increasing political pressure and regulation, due to their more polluting nature. Governments increasingly regulate these activities and coal generation especially faces an existential threat throughout Europe, combined with growing risks connected to waste and pollution through the creation of coal ash and particles. We believe that the phase-out scheme will pave the way for Uniper's German coal exit sooner than EnBW. This said, in the overall picture we continue to see EnBW's business as stronger than that of Uniper. This is because of EnBW's 50% of regulated activities and subsidized renewable base, against Uniper's fully unregulated activities, larger commodity price exposure, and operations in Russia, which we view as a country bearing higher risk than Germany.

We believe that the impact in issuer's business risk profile could be more relevant than that the financial impact in the future because these assets already operate under low profitability conditions. Market activity in 2019 values European coal assets at most between €100 million-€110 million per GW of installed capacity. For example, French integrated utility Engie sold 2.3 GW hard coal capacity in Germany for €250 million to Riverstone in April 2019. In our opinion, market conditions and prospects have worsened for coal assets since then. However, until 2022, the compensation provided by the German government exceeds this amount which, although depending on the asset, could be credit positive for Vattenfall and Uniper. Because of the auction mechanisms, however, and the fact that we expect earlier auction processes to have more participants, compensation could come close to market valuation, reducing compensation for operators.

The exposure to the imminent phase-out for each player varies depending on the location of the plants and the share of the electricity coal represents from its produced output. Plants located in the southern part of Germany (see charts 5 and 6) will have fewer chances to participate in the auction process because the recently approved law only allows a company to submit a successful bid if the shutting down of a plant does not pose a risk for grid stability and security of supply.

Chart 5


EnBW has more limited capacity to close its plants

The states of Baden Wurttemberg and Bavaria, located in southern Germany, are important industrial centers with high power demand, and already facing power deficits at times. By 2023, these states will lose about 6.7 GW of installed nuclear capacity, which will make the southern coal plants even more critical to alleviate a widening power deficit. This is especially the case given that we don't anticipate the high voltage transmission projects Suedlink and SuedOstLink (each with 4 GW capacity), which would otherwise transport the increasing renewable generation from northern Germany to the south, to be ready before 2026 and 2025. Therefore, we don't conisder any accelerated coal exit for southern coal capacity is likely until after that year, meaning that such capacity is unlikely to benefit from the auction mechanisms.

In fact, EnBW registered about 1.7 GW of its installed thermal capacity for decommissioning in 2019 but these plants were classified as system relevant by the BNetzA, and therefore will be used as reserve grid capacity by TransnetBW, one of Germany's four transmission system operators (TSOs). We see this as unfavorable for EnBW compared to the rest of the issuers, as they will have to stick to unprofitable and CO2-intensive coal assets for longer, likely without closure compensation later on.

Chart 6


We see Uniper as a likely key beneficiary of the coal exit plan

We conisder that Uniper, with the largest individual hard coal capacity, has more flexibility to close than EnBW because most of its capacity is located in an area where the company can successfully participate in the bidding process. In addition, about 1.1 GW of Uniper's capacity corresponds to its newly commissioned and highly efficient Datteln 4, an asset that will not be part of the BNetzA auctions and which we expect to be operational until 2035, but which is backed by a 15-year power purchase agreement (PPA) that will secure the asset's profitability and earnings visibility. For both companies, coal assets represent around 26% of its generation capacity (although for Uniper only 11% is located in Germany and the rest in the U.K., the Netherlands, and Russia). In addition, both companies generate close to 20% of their total electricity from coal and lignite (see charts 7 and 8)

Chart 7


Less meaningful upside for Vattenfall and EVN

Vattenfall is the least exposed out of our rated issuers because of the minimal share that its Hamburg Moorburg plant represents out of its total generation capacity, which we see as diversified. Although the 1.7 GW plant comprises about 55% of its hard coal generation capacity, it only represents 5% of the group's consolidated power generation capacity. Austrian utility EVN is indirectly affected because of its 49% participation in the 725 megawatt (MW) hard coal Walsum-Duisburg power plant (the other 51% owned by STEAG Group), commissioned in 2013.

Chart 8


A Neutral To Favorable Credit Impact For Rated Utilities

Coal operators are adopting different strategies, according to their location and ability to exit coal. In general, we see the impact as neutral to favorable for our rated issuers, although not to the extent that it would lead to rating changes. Rather, it better allows companies to accelerate the transition to greener fields and reduce polluting generation in their portfolios.

Chart 9


We see thermal capacity and its related carbon intensity as a negative factor in our assessment of a power generator's business risk profile. This is because, on the one hand, these assets are facing increasing regulatory hurdles and social pressure. On the other hand, as carbon costs continue to increase, carbon-intensive assets' competitive loss against cleaner generation increases. In addition, coal capacity typically is more costly to decommission than, for example, gas, and renewables other than offshore wind, implying at the same time larger AROs, which we view as debt-like obligations.

As of 2020, we see Uniper as the company with the highest thermal share of its total installed capacity among peers in chart 9, and a high volume of CO2 emissions among peers. Although this is only one of multiple components, it partly explains why we see Uniper's business risk profile one notch weaker than that of peers. This is also why we believe Uniper is the operator that can benefit the most from a controlled coal exit strategy. EVN, a company also constrained due to its high share of thermal capacity, could also move to the lower end of the spectrum, depending on the timing of the shutdown of the 725 MW Walsum coal plant, which it partially owns. EVN shut down its 332 MW Dürnrohr power plant in 2019, five years ahead of schedule, reflecting its intention to move away from coal. On the other hand, while EnBW has a lower thermal share as a percentage of total capacity, and also lower carbon emissions, the company does not have much flexibility to reduce until the end of the current decade. Vattenfall benefits from a low carbon intensity portfolio, with nuclear and renewables making up for close to 75% if total power generated.

The table below summarizes each player's strategy, with an immediate exit for Vattenfall, an accelerated one for Uniper, and a less favorable path for EnBW.

Table 2

Utilities Peer Comparison And Coal And Lignite Exit Strategies

Uniper SE

EnBW Energie Baden-Wuerttemberg AG

Vattenfall AB



Ratings as of Nov. 16, 2020 BBB/Negative/-- A-/Stable/A-2 BBB+/Stable/A-2 A/Negative/-- Not rated
Business Risk Profile Satisfactory Strong Strong Strong N.A.
Regulated 0% 47% 33% 50% 0%
Unregulated 100% 53% 67% 50% 100%
Total generation 2019 (TWh) 104.0 47.8 129.3 5.5 152.7
Total installed capacity as of 2019 (GW) 34.3 13.8 30.5 1.7 42.9
Lignite 3.2 0.8 0.0 0.0 10.3
Hard coal 7.1 3.6 2.9 0.4 4.0
Nuclear power 1.4 2.9 7.2 0.0 2.8
Gas 17.4 1.2 4.7 0.6 14.0
Pumped storage 0.0 0.5 0.0 0.0 0.0
Other thermal 0.0 0.3 0.7 0.0 0.4
On and offshore wind 0.0 1.7 3.0 0.4 7.8
Pumped storage (natural flow of water) 0.0 1.5 0.0 0.0 2.4
Hydro 3.6 1.0 11.7 0.3 0.6
Other renewable 2.8 0.2 0.3 0.0 0.7
Coal exit strategy - Entering in auctions if possible, depending on offtake agreements and enployee job security factors - Shutting down all coal-fired power plants in Germany over next five years (excluding Datteln 4) - 1.5 GW (Wilhelmshaven and Scholven) phased out in 2022 - 1.4 GW (Staudinger and Heyden) phased out in 2025 - Exited lignite by selling stake in Schkopau to EPH, effective October 2021 - Limited ability to shutdown coal capacity because of grid stability considerations - By 2030, EnBW will withdraw 2.6 GW capacity, with 1.9 GW remaining - Examine possibility of converting plant to gas, before moving to carbon-free generation, such as hydrogen - Already applied for compensation under the September 2020 auction for its 1.7 GW Hamburg Moorburg plant, Vattenfall only coal capacity in Germany. - 800MW of capacity could be converted to gas in order to provide heating. - EVN is moving away from coal - Dürnrohr plant (332MW) closed in 2019, six years ahead of schedule - The comapny remains with a non-controlling stake at Walsum 725MW power plant, jointly owned with STEAG Group - Decision to close depends in a agreement between both EVN and its partner - Determined by lignite phase-out
(Mil. €) --Fiscal year ended Dec. 31, 2019-- Fiscal year ended Sep. 30, 2019 N/A
Financial Risk Profile
Revenue 65,804.0 18,765.0 15,868.9 2,318.7 --
EBITDA 1,702.0 2,303.0 3,828.7 670.2 --
Funds from operations (FFO) 1,490.0 1,689.8 3,420.7 626.3 --
Interest expense 178.0 520.8 381.8 45.7 --
Cash interest paid 165.0 204.1 262.3 42.7 --
Cash flow from operations 843.0 789.4 1,591.0 444.1 --
Capital expenditure 566.0 1,920.6 2,474.3 390.6 --
Free operating cash flow (FOCF) 277.0 (1,131.2) (883.3) 53.5 --
Discretionary cash flow (DCF) (84) (1,485.7) (1,380.1) (52.7) --
Cash and short-term investments 871.0 1,105.9 3,162.6 335.9 --
Debt 1,580.4 10,735.7 12,002.6 1,084.4 --
Equity 11,942.0 8,684.4 11,313.5 4,552.1 --
Adjusted ratios
EBITDA margin (%) 2.6 12.3 24.1 28.9 --
Return on capital (%) 7.3 5.1 8.8 7.5 --
EBITDA interest coverage (x) 9.6 4.4 10.0 14.7 --
FFO cash interest coverage (x) 10.0 9.3 14.0 15.7 --
Debt/EBITDA (x) 0.9 4.7 3.1 1.6 --
FFO/debt (%) 94.3 15.7 28.5 57.8 --
Cash flow from operations/debt (%) 53.3 7.4 13.3 41.0 --
FOCF/debt (%) 17.5 (10.5) (7.4) 4.9 --
DCF/debt (%) (5.3) (13.8) (11.5) (4.9) --
*Uniper's hard coal capacity does not include 1.1GW Datteln 4 capacity commissioned in 2020. GW--Gigawatt. N.M.--Not meaningful. N.A.--Not applicable. MW--Megawatt.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Gerardo Leal, Frankfurt + 52 55 5081 4450;
Bjoern Schurich, Frankfurt (49) 69-33-999-237;
Secondary Contacts:Pierre Georges, Paris (33) 1-4420-6735;
Per Karlsson, Stockholm + 46 84 40 5927;
Renata Gottliebova, Dublin +353 1 568 0608;

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