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Can Carbon Border Adjustments Push Russia's Electricity Industry Toward Net Zero?

(Editor's Note: This report by S&P Global Ratings and S&P Global Platts Analytics is a thought leadership article that neither addresses views about ratings on individual entities nor is a rating action. S&P Global Ratings and S&P Global Platts are separate and independent divisions of S&P Global.)

S&P Global believes Russia will lag Europe, the U.S., and China in reducing greenhouse gas (GHG) emissions, particularly from its power industry. Russia has long prioritized the supply of stable and affordable electricity over environmental targets. What's more, its vast hydrocarbon reserves make domestic gas-fired power generation a stable, low-cost business. Pressure from global environmental-protection initiatives is mounting, however.

CBAM, part of Europe's Green Deal initiative, will impose new taxes on imports linked to high-emission production. Although details of the mechanism are not yet final, CBAM could hurt Russian exporters' cost competitiveness. The EU is Russia's biggest trading partner, accounting for 37.5% of the country's goods exports in 2020. Russia's main export-oriented industrial sectors, including oil and gas, metals and mining, chemicals, and fertilizers, rely heavily on electricity. Platts Analytics estimates that Russia's power producers generate more CO2 than those in Western Europe or the U.S., at 0.50 tonnes of CO2 per kilowatt hour (t/kWh) of electricity delivered, versus 0.20 t/kWh and 0.37 t/kWh respectively; that's only slightly higher than the global average of 0.48 t/kWh.

But things are slowly changing. Since Russia ratified the Paris Agreement on climate change in September 2019, it submitted an updated Nationally Determined Contribution in late 2020 that requires emissions to be 70% below 1990 levels by 2030 (including land-use changes). Also, within Russia, there has been a massive push for initiatives to improve climate disclosure amid increasing calls for greener energy from end users and investors. New legislation to move things along is underway, including the law on carbon certificates passed by the State Duma in June 2021, and regional decarbonization pilots in Sakhalin and other regions. Still, it remains to be seen how much progress can be achieved before CBAM goes into force in two years' time.

Carbon Reduction Or Emission Comparison?

The November 2020 presidential decree that set an emissions-reduction target of 70% compared with the 1990 level (when adjusted for land use and forestry) also allows for emissions to increase to foster economic growth. And although the president stated recently that Russia's net accumulated emissions over the next 30 years should be below the EU's, no specific target or strategy to achieve this has been announced. The government is expected to present an updated long-term GHG strategy in October this year.

However, Russia already generates less carbon dioxide (CO2) than the EU, at about 1.7 billion tons annually versus about 2.9 billion tons for the EU in 2019. This implies it may not need to reach net zero by 2050 to achieve its goal, and may keep emissions stable depending on the EU's decarbonization path and the methodology for calculating net GHG emissions. For example, theoretically, taking atmospheric lifetime and land-use changes into account, Russia could potentially meet its long-term target--without any substantive change to emissions from combustion--should the EU's 2050 emissions decline to only 50% of current levels.

That said, if the EU manages to achieve deeper cuts to emissions, this could complicate Russia's targets. The Russian Ministry for Economic Development's "inertia scenario" forecasts Russia's own emissions to reach 76% of its 1990 levels by 2050, and a case "without supporting measures" projects further recovery to 90% of 1990 levels. But both projections would be inconsistent with the overall goal of reducing cumulative net emissions below the EU's own cumulative delta, should emissions in the EU drop by more 50% over the next three decades. Even if the energy transition in the EU is delayed and emissions increase in the medium term as the region recovers from the pandemic, the setback will likely be brief. EU emissions have declined steadily over the past few decades and peaked in the early 2000s. Aggressive decarbonization as the EU delivers on its net-zero pledges would require corresponding reductions in Russia.

Chart 1


CBAM Will Put A Price Tag On Russia's Carbon Footprint

Currently, there's no domestic carbon price mechanism in Russia. However, CO2 emissions from electricity generation will be increasingly important for the country's industrial users, especially exporters, listed companies, and those with environmental goals. The mining and industry sectors consume as much as 58% of the energy produced, and households only 16%.

The EU plans to release details of CBAM in July 2021 and implement it two years later. We believe Russian exporters can manage the financial impact over the next several years (see "How Russian Companies Are Responding To Growing ESG Pressures," published Feb. 8, 2021). Still, in the longer term, the carbon intensity of electricity purchased may become key for competitiveness as the emissions gap between Russia and the EU widens. CBAM could cost Russian exporters €3 billion-€6 billion per year in tariffs, according to estimates from KPMG and Boston Consulting Group at midyear 2020. Since then, the EU Emissions Trading System (ETS) carbon price has increased, surpassing €50 per metric ton in May 2021 compared with about €30, and the ETS' list of in-scope industries has become longer.

For Russian exporters and, by extension, their electricity suppliers, critical areas of CBAM to be clarified include reporting and verification standards (for instance the scope, market versus location method, and acceptability of various types of carbon offsets), as well as the list of industries included at various CBAM stages, not to mention the eventual price of EU carbon units.

Russia's Finally Pushing For A Greener Future

This month, the lower house of Russia's parliament, the State Duma, approved draft legislation on decarbonization, green certificates, and climate projects; and there is little doubt the upper house and the president will eventually approve it. The draft requires large companies to report emissions, and introduces the concepts of climate projects and trading in carbon units. Still, Russia's 2020 energy strategy is focused on reducing emissions by increasing efficiency--for example through better fuel utilization, lower grid losses, and energy-efficient buildings--rather than via renewables.

In addition, the Ministry for Economic Development and state-owned development corporation VEB have submitted proposals for Russia's own green taxonomy. The government has also approved a roadmap to make Sakhalin the first region to achieve net-zero-emission status by 2025. The roadmap requires a regional CO2 trading system to start functioning in September 2021-July 2022 and to be synchronized with appropriate international systems. Other regions, such as Kaliningrad, are also looking into pilot decarbonization programs.

Many Russian corporates, as well as international companies operating in Russia, are voluntarily setting emission-reduction targets amid mounting environmental pressure from investors and contractors along the value chain. Overall, Russian companies are becoming increasingly sensitive to the carbon footprint of electricity they purchase.

To reduce emissions reported by export-focused assets, some large Russian companies intend to restructure their asset portfolios based on carbon intensity. For example, steelmaker Evraz plans to sell its coal-mining assets, and aluminum producer Rusal is considering a spin-off of its high-emission mining, alumina, and aluminum production assets. Rusal, to be renamed AL+ if the spin-off proceeds, will focus on exports and the new company on developing the domestic market. Carbon-led corporate restructurings are not unique to Russia and happen in other countries too. Although asset reshuffling cannot bring down emissions, it illustrates that companies are becoming increasingly sensitive to their reported carbon footprint.

Rising Interest In Carbon-Free Energy Could Benefit Hydro And Nuclear

Despite having a more carbon-intensive power industry than in many European countries, about 40% of Russia's electricity came from low-carbon nuclear and hydropower production in 2020. This translates into 36%-38% after adjusting for extraordinarily high hydropower production and unusually low electricity demand last year. On paper, this proportion of non-fossil energy should cover the needs of the country's largest exporters and other energy consumers that face environmental reporting requirements or have emission-reduction targets. Russia's biggest rated hydro and nuclear producers are AEPC and RusHydro, followed by TGC-1.

Large industrial consumers in Russia are increasingly interested in direct power-purchase contracts with such carbon-free electricity producers. An example is RusHydro's one-year direct bilateral contract with Polyus, signed in February 2021, to supply 1GWh, in addition to a five-year contract signed in 2020 for 300MWh per annum. In April 2021, Polyus acquired international renewable energy certificates (I-REC) from TGC-1 and Vitimenergosbyt for production at their hydro assets. Together, these would cover all of Polyus' electricity requirements with carbon-free hydropower.

Similarly, Rusal has PPAs with hydropower producers in Siberia where its key aluminum smelters are located. Although the details have not been disclosed, we understand such contracts are unlikely to be a disadvantage for power producers versus day-ahead market rates and can support capacity utilization for renewables players; this, however, makes little difference for nuclear and hydro producers, which by the market's design already enjoy priority access. Currently, the market for PPAs on carbon-free electricity is nascent, but we cannot rule out the emergence of green premiums in future.

Could Carbon Certificates Make A Difference?

Russia is about to adopt legislation on carbon certificates allowing purchasers of carbon-free electricity to do so without long-term commitments under take-or-pay agreements. Direct contracts with low-carbon electricity producers are also allowed, but they could eventually affect capacity utilization for higher-carbon electricity producers with significant sales of socially important heat. Certificates are not linked to physical electricity supply and therefore could be more acceptable for regional governments and communities.

In line with current proposals, Russian carbon certificates would cover renewable as well as nuclear and large hydro generation. Although nuclear and large hydro are not included in the current draft of the European green taxonomy for reasons related to biodiversity, safety and nuclear waste, they are effectively carbon free.

It remains to be seen whether the EU would accept Russian carbon certificates or PPAs as a means of reducing the reported carbon emissions of Russian exporters, and therefore their carbon payment. Two important issues arise here: one relates to reporting and verification, and the other to the impact on future emissions. A third possible area of complexity concerns how carbon certificates might be awarded.

Environmental reporting is evolving in the EU and in Russia but not necessarily in parallel, so regulatory harmonization is paramount for Russian companies.  In its March 2021 resolution to adopt CBAM, the European Parliament stressed that foreign companies should have the option to prove--in accordance with EU standards for monitoring, reporting and verification--that the carbon content of their product is lower than EU levels. This would not only reduce the amount foreign companies have to pay, but also create an incentive for innovation and investment in sustainable technologies.

Even if Russian-issued certificates are not accepted internationally, Russian producers of non-carbon electricity might attempt to obtain international certificates. EN+, for instance, obtained I-REC in late 2020 for its solar generation operations, and TGC-1 did so in 2021.

More fundamentally, although green certificates or PPAs for nuclear and hydropower can help improve reporting, they do not change Russia's underlying fuel mix and overall emissions.   Consequently, they do not correspond to the stated ultimate goals of the EU's green policy and CBAM. Rather, they allocate existing low-carbon electricity to emission-sensitive customers (such as exporters, or companies with emission-reduction commitments), while high-carbon electricity goes to customers that do not need to report their carbon footprint, have no emission-reduction targets, or are unwilling or unable to pay for green certificate (for example, domestically focused small and midsize enterprises). In theory, green certificates may encourage higher production of lower-carbon electricity at some point. But if they apply to Russia's already large hydro and nuclear electricity generation, and are cheaper than other ways to reduce the emission count (via investments in energy efficiency or renewables, for instance), the impact on the fuel mix is unlikely to be large.

Another potentially contentious issue relates to the allocation of green certificates.   Historically, significant hydro, nuclear, and renewable capacities went hand in hand with a capacity supply agreement (CSA), which guaranteed the return on investment via future capacity revenue. Arguably, customers have already paid for existing non-carbon generation via CSAs and can claim green certificate allocations. Still, administering such "green vouchers" is complex. Customers' capacity payments have included nuclear, hydro, renewables, and thermal generation in different proportions for years. Also, the potential for additional revenue from green certificates could be factored in via lower prices from producers at renewables auctions. It remains to be seen whether free allocation would hurt the credibility of Russian green certificates in the eyes of international regulators.

The Pandemic Won't Complicate Matters For The Industry

The impact of COVID-19 on the Russian electricity sector has been very manageable. In 2020, electricity consumption in Russia was down only 2.4% versus a GDP decline of 3.5%, but with significant variations across regions (see chart 10). While industrialized regions in Volga-Urals and North West were hit by the economic downturn and OPEC+ agreement, electricity consumption in the Far East continued to rise. From the second half of the year, Russia's electricity output started rising on the back of economic recovery and the cold weather, so in December 2020, production was 2.2% above the 2019 level. In first-quarter 2021, electricity production at United Energy Systems increased by 3.3% and consumption by 4% (excluding the effect of the additional day due to the leap year), surpassing GDP growth.

Chart 10


Despite widespread concerns about customer nonpayment during the pandemic, collection rates were generally stable. The largest electricity consumers in Russia are industrials, which continued operating through the lockdowns. Collection shortfalls were limited to a handful of large offtakers (such as TNS and North Caucasus), whose payment track records were patchy even before the pandemic. Arrears from domestic customers during the April-May 2020 lockdown were largely paid up in subsequent months.

COVID-19 has delayed certain capital expenditure (capex), however, including Leningrad NPP (a nuclear power project) by several months and several renewables initiatives. For example, Enel Russia obtained a grace period to avoid penalty payments after commissioning of its 90MW Azov windfarm was postponed to March 2021 from December 2020; it has received the right to start commercial electricity supplies in May 2021. We understand such grace periods can be granted in specific cases but neither the Market Council nor government view the pandemic as a force majeure, which could mask deficiencies in a project's implementation. Because the Russian energy system has significant spare capacity and power demand is not increasing that fast, commissioning delays were not critical.

Electricity Bills Will Go Up, But Not Due To CBAM

We believe the total customer energy bill in Russia will increase gradually due to higher capacity payments to power producers. Nuclear and hydro companies will benefit, while thermal generation revenue will likely shrink. The government influences capacity prices according to its energy policy priorities, asset modernization needs, and market demand dynamics.

At the same time, it aims to limit the increase in all-in electricity costs to keep tariffs affordable for the population, meet social goals, and support economic growth. For example, in 2019, a relatively large 41% of end-users' electricity payments (net of transmission, distribution, and retail services) stemmed from fixed capacity revenue, and 59% from variable electricity sales (source: ATS-Energo). Solid capacity payments make Russian generation revenue fairly predictable but they remain subject to frequent political intervention.

Three main factors determine the fixed capacity payment in 2021-2025: capacity supply agreements (CSAs), government surcharges, and rising commercial (COM) capacity prices. Its structure is changing to benefit nuclear, hydro, and renewable power producers (such as AEPC and RusHydro), while traditional thermal generation companies (TGC-1, Mosenergo, and the Russian units of Fortum and Uniper) will see capacity revenues dwindle in the coming years (see chart 11).

Chart 11


Capacity prices under CSAs are usually several times higher than under commercial capacity auctions.  CSAs for all types of generation provided 20% of capacity sales and 58% of capacity revenue (see charts 12 and 13). That's because CSAs are designed to ensure a guaranteed return on government-approved electricity generation projects, all of which were completed by year-end 2020. CSAs ensured a very attractive 10%-15% return in rubles, initially over 15 years but subsequently accelerated to 10 years. The new CSAs for thermal capacity modernization are relatively small. The first wave of thermal CSAs will expire in 2021-2023, and CSAs on new, more expensive nuclear, hydro, and renewable assets with a higher price per MW of capacity will kick in. New capacity commissioned in 2020 include the Novovoronezh nuclear unit, Zaramagskaya HPP (hydro), and large renewable operations. This year, the 1.2GW Leningrad nuclear unit started in March, and more renewables projects should start in 2021-2022.

Chart 12


Chart 13


The cost for end users also includes surcharges aimed at broader policy goals.   For example, the government introduced a special surcharge aimed at ensuring affordable electricity prices in the remote but politically important Far East District. This surcharge totaled Russian ruble (RUB) 46 billion in 2020, up from RUB40 billion in 2019.

The COM capacity price is already set to increase over 2021-2025, while staying below the CSA rate.   The looming expiration of CSA-1 will cut EBITDA for traditional thermal generation. The regulator therefore raised the auction's upper limit to soften the blow and allow for modernization of thermal generation units that weren't selected for the second round of thermal CSAs. In 2020, despite lower electricity demand, the all-in electricity price increased (see chart 14). This is because the fixed charge for new CSA capacity and growing regional surcharges had to be allocated to lower electricity consumption. The market council estimates that surcharges above the COM price added RUB558 billion, or over 60% of the capacity payment, to the total customer bill in 2020.

Chart 14


Although the average electricity price is relatively low, increasing capacity prices and sizeable cross-subsidization create incentives for Russian industrial and commercial customers to develop inhouse generation facilities, invest in energy savings, and manage their demand patterns.

What's Fueling Spot Prices: Gas On The West, Coal On The East

Spot electricity prices in Russia are generally less volatile than in some other large developed markets, even adjusting for the inherently stable capacity component (see chart 15). We believe this is likely to continue because of a high share of baseload, inherently stable regulated or quasi-regulated gas prices, and low and intermittent renewables generation.

Chart 15


The main factors influencing price depend on the region (see chart 16:

In Price Zone 1 (the European part of Russia), gas-fired generation dominates the energy mix and is the main price-setter. 

  • Coal-fired generation is minimal here. Due to the design of Russia's electricity market, nuclear and hydro power stations are price takers and have priority access to the market for their volumes. Unlike in Europe, gas prices are largely independent from global benchmarks and usually below the global average, except for the first half of last year when international prices were at record lows. Gazprom, which typically meets more than 50% of domestic gas needs is regulated, and other gas producers usually adjust their prices close to regulated levels. In 2020, Gazprom realized an average domestic price of RUB4,177 ($57.9) per thousand cubic meters, and the government continues to raise regulated domestic gas prices by about 3% annually in ruble terms. Domestic gas price liberalization is not on the agenda. This is a fundamental difference from the liberalized, highly volatile EU gas markets.

In Price Zone 2 (Ural-Siberia), prices are more volatile due to volume fluctuations inherent to hydro generation, a price taker.  

  • The main price-setter is coal from nearby mines. Domestic coal prices are not regulated and can indirectly depend on export net-back and transport costs, given significant coal exports from Russia.

In remote areas, such as the Far East, prices are regulated, and heavily influenced by social and affordability considerations.  

  • Local generation costs are high due to difficult fuel logistics, aged generation assets, and insufficient economies of scale in these large, scarcely populated areas. Since July 2017, the government has set end-user tariffs at the country average level, and covers the difference versus high local energy costs with a special surcharge on electricity consumers in the European and Ural-Siberia zones. In the Far East, this is done via RusHydro, the district's main electricity producer.

Chart 16


Government's Taking A Measured Approach To Renewables

Compared with the EU's massive renewables support packages, the Russian government's support for the sector appears cautious. Renewables enjoy special CSAs, similar in principle to those used for construction and modernization of traditional thermal, hydro, and nuclear assets. This is quite unusual given the inherent intermittency of renewables generation, and contrasts with feed-in tariffs or subsidies common in the EU. Also, in Russia, renewables support mechanisms entail stringent content requirements, enabling the government to mitigate sanction risks.

The local content requirements for the first renewables CSA program--from 2020 to 2024--are 65% for wind assets, 70% solar, 65% small hydro; and for the second CSA they were increased to 90%. The goal is to commission 3.4 GW of wind, 2.2 GW of solar, and 0.2 GW of small hydro capacity over that period. The biggest renewables players include Fortum, Rosatom, and Enel Russia. Fortum, via a joint venture with the state-controlled Russian Direct Investment Fund and other entities, has contracted 1,858MW of wind and 151MW of solar capacity (55% of the government's first renewable program). Rosatom's biggest renewable assets are a 970MW wind park, VetroOGK, and 220MW VetroOGK-2.

Since the first wave of renewables CSAs has been contracted, the government plans new auctions for the second round in August 2021-September 2021. In June 2021, the government cut the size of the second program (CSA-2) to RUB360 billion from RUB400 billion. The key goal of this is to limit the increase in customers' bills. The government's target for CSA-2 is to add 5.4GW of renewables capacity in 2023-2035, including 1.8GW of solar, 3.4GW wind, and 0.2GW of small hydro.

We don't think the cut in CSAs this time around will affect the direction of renewables in Russia, which is increasingly fueled by economic incentives rather than regulation. CSA-2 sets strict and costly requirements for local content, unique commitments to export renewable generation equipment, and minimal production levels. If these are not met, the capacity payment will be materially lower. Unlike for thermal, nuclear, and even hydro generation, renewables volumes are inherently very volatile, and equipment exports add extra complications. Meanwhile, CSA-2 auctions are based mainly on the LCOE. This highlights that renewables generation in Russia is becoming more cost competitive and less reliant on regulatory support.

The Share Of Renewables Will Stay Modest

In Russia, the share of renewables in the energy mix is much lower than in many other markets. Solar and wind generation increased by over 80% to 2,200 MWh last year, but still represented only about 1% of installed capacity and a mere 0.3% of generation volumes. We expect renewables to gradually expand, but due to corporate interests rather than government support, and to less than 10% of the energy mix. Solar and wind electricity generation will likely remain well below EU or global levels, due to several factors.

The average cost of wind and solar generation is a lot higher in Russia than for traditional gas-fired generation and energy producers in many other countries.   The main reason is the low domestic gas price. However, another key factor is that Russia's most densely populated regions (such as Moscow, St. Petersburg, and environs) lack solar and wind resources. Russia's windiest areas, near the Arctic coast, are scarcely populated and generation equipment needs to be suitable for the area's terrain (lack of transport infrastructure) and harsh weather conditions (such as snow and frost). Renewables growth stems mainly from southern regions with more suitable climates and sufficient electricity demand, such as Orenburg, Stavropol, Rostov, Astrakhan, and Samara.

Recent auctions show a marked decline in renewable energy costs, partly due to increased capacity utilization.   In 2020, some new bids for wind projects were well below certain new nuclear and coal-fired projects: at about RUB65,000 per kWh, for example (see chart 17). This follows the successful start of equipment manufacturing by international and local players. Vestas started producing wind turbines in Ulianovsk with Rusnano (supplied Fortum's projects), Siemens opened a wind turbine manufacturing facility in Leningrad Oblast (Enel's Azov and Kolsky wind projects), Rosatom is developing its wind turbine production, and Hevel is producing solar modules in Novocheboksarsk, Chuvashia (over 300 kW of solar capacity annually). The availability of local equipment is important because of strict component requirements to qualify for the government's renewables support scheme. Greater renewables capacity utilization has also pushed production costs down. In 2020, wind use increased to about 27% from about 20% in 2019, and solar to 15% from 14% after the commissioning of units in suitable locations. This is comparable with EU figures. Minenergo expects wind and solar to achieve grid parity in Russia by the middle of the next decade.

Chart 17


Renewables Progress Relies On Corporate Appetite

Beyond regulations, we believe large industrial companies, especially exporters and those with climate commitments, could spur renewables development.   Conditions appear favorable. The cost of producing renewables energy is declining, despite remaining more expensive than gas. Increasing all-in electricity bill could make investing in in-house generation including renewables economically attractive for certain industrial and commercial customers, depending on weather conditions and the tariffs in their region. Already, we see concrete steps toward greener energy from large international and local players, such as Fortum and Rosatom. Also, with few growth areas for traditional generation after major CSA projects are completed, utility companies could start exploring investments in renewables.

As industrial and commercial customers face mounting electricity bills, at some point they may conclude it might be cheaper to invest in their own generation facilities, including renewables.  Surcharges, capacity payments, and cross-subsidization of residential sector will push up industrial users' electricity bills. This could make inhouse power production a viable option for them, as well as a direct way to reduce emissions that's not as dependent on regulatory developments as green certificates or PPAs. For example, Russian oil company Gazpromneft uses solar panels on its refinery in Omsk, a city that enjoys 308 sunny days per year on average. Lukoil uses renewable energy in its Bulgarian and Romanian operations and has been investing in solar panels at its oil refineries in Samara and Volgograd. Small and midsize enterprises in the south of Russia are increasingly looking at rooftop panels as a way to reduce their electricity bills, especially after the law on microgeneration was adopted. Also, some of Russia's remote regions feature very costly, often aged, and inefficient traditional generation units. For isolated energy systems in scarcely populated areas with poor logistics (such as the Arctic and Far Eastern districts), a distributed energy system based on renewables and backed with thermal generation could be cheaper than transmission grids. Luckily, some of those areas have relatively favorable solar and wind conditions (Arctic seashore, Primorsky, Khabarovsky Krai, and Buryatia). That said, fluctuating weather conditions imply the need for massive energy storage units or backup generators.

But there are no clear economic incentives for private players to invest in renewables as long as the government continues to subsidize the cost of fuel supplies in certain remote areas (so called Northern Supply).  Wind and solar equipment would need to be customized for harsh weather conditions, which could make them more expensive, and need to be supplied to areas where transport infrastructure is limited. At the same time, the impact of wind and solar installations on local biodiversity and traditional lifestyles needs careful consideration.

Hydrogen may offer interesting growth opportunities for Russian renewables in the future.   For example, Enel is considering producing hydrogen at its Kolsky wind unit (currently under construction) for export to neighboring Nordic countries. We believe that will depend on cost and regulations, because Kolsky is being built under a CSA. Russia's nuclear power producer Rosatom and its subsidiary AtomEnergoProm both have significant potential to produce yellow hydrogen. In April 2021, EDF and Rosatom agreed to collaborate on promoting CO2-neutral hydrogen in Russia and Europe, which might create a platform for technological advancement in the future. Rosatom has an agreement with the Sakhalin region's government to develop a facility complex to produce 30,000 tons-100,000 tons of hydrogen annually for the Asia-Pacific market, and plans to launch a hydrogen-fueled pilot train in the region. Still, we understand these plans are at a nascent stage, as is the global hydrogen market, with little certainty about demand or supply demand.

Appendix: Key Rated Companies

Rated Russian Energy Companies

Atomic Energy Power Corp. JSC

RusHydro PJSC

Mosenergo PJSC


Fortum/Uniper (cons.) with and without Russia

Issuer credit rating BBB-/Stable/A-3 BBB-/Stable/A-3 BBB-/Stable/-- BBB-/Stable/A-3 BBB/Negative/A-2
SACP bbb- bb+ bbb- bbb- bbb-
Share of Russian business in EBITDA, including exports (%) 100 100 100 100

About 25

Installed capacity in GW (YE2020) 31.0 38.0 13 7 50
Power generation in TWh (YE2020) 216 131 54 28 142
Generation mix (2020) 99.9% nuclear, 0.1% is RES 79.3% hydro, 20.4% thermal, 0.3% RES 99.3% - gas, the rest is fuel oil + coal 47% hydro, 53% thermal (more than 98% of thermal is gas, the rest is fuel oil and coal) 45% gas, hydro 23%, nuclear 20%, coal and lignite 9%, renewables (incl. biomass) 2%
Carbon intensity gCO2/KWh 4.5 230 681.6 311.7 287 (Russian assets - 418)
Adjusted 2020 financial metrics (mil. €)
EBITDA 3,580.3 1,337.8 378.8 257.2 2,955
Funds from operations (FFO) 2,378.9 993.7 316.1 230.7 2,480
Free operating cash flow (213.9) 343.2 177.8 83.0 1,454
Adjusted debt 1,925.5 1,410.7 66.3 283.6 9,878
FFO/debt (%) 123.5 70.4 476.7 81.4 25.1
Debt/EBITDA (x) 0.5 1.1 0.2 1.1 3.3
CO2--Carbon dioxide. RES--Renewable energy sources. Source: Company data, S&P Global Ratings.

We believe that, generally speaking, the power companies we rate in Russia will continue to display solid financial metrics in 2021-2023. In our base case, we assume:

Mosenergo and TGC1:  

  • Revenue and EBITDA will decline materially in 2021-2022 because CSA-1, mostly aimed at thermal generation, will expire and be only partly offset by higher commercial capacity prices and the relatively smaller CSA-2 for modernization, also renewable CSA for small hydro for TGC-1). Both companies have very low reported debt, the lower EBITDA should be sufficient to cover modest capex, and dividends are fundamentally flexible. Ultimate parent company, Gazprom, has wider access to funding and is therefore, in our view, unlikely to increase debt at the utility subsidiaries.


  • With large hydropower capacity and assets located close to the border with Finland and the Baltics, TGC-1 is well positioned for exports and the domestic sale of carbon-free green electricity or certificates if the market structure is in place.


  • Record high RUB23 billion dividends after a very strong 2020 when EBITDA reached RUB121 billion, thanks to high water levels and outstanding operational results. Even with normalized water levels, the addition of 508MW of new capacity in 2020 will likely boost earnings from 2021, funds from operations to debt staying above 45% despite the higher dividend, assuming economic activity in Russia rebounds.


  • Benefits from very low debt, increasing capacity revenue as new nuclear units start operating, and manageable domestic capex with only two units left to be completed. AEPC has already accumulated significant financial resources for its biggest international project, 4.8GW Akkuyu in Turkey, and received partial equity support from the Russian government (approved for up to $1.8 billion, compared with the $22 billion total cost through 2026). Despite investments potentially reaching RUB500 billion per year in 2022-2024, we forecast debt to EBITDA staying below 1.0x in the medium term.

Fortum and Uniper:  

  • Historically, Russian operations provided Fortum and Uniper with stable profits supported by solid capacity sales, and the main uncertainty came from foreign exchange fluctuations. However, the profitable thermal CSAs will soon expire, and the assets' carbon footprints were above the company-average even before the recent re-start of Berezovskaya coal-fired plant, which doesn't escape investors' attention. Fortum's zero-carbon wind assets are at the level of its joint venture with the state-controlled Russian Direct Investment Fund and therefore not consolidated.

Editor: Bernadette Stroeder. Digital Design: Tom Lowenstein.

Related Research

External Research

  • Lu, Xi, Michael B. McElroy, and Juha Kiviluoma. 2009. Global potential for wind-generated electricity. Proceedings of the National Academy of Sciences of the United States of America 106(27): 10933-10938

This report does not constitute a rating action.

S&P Global's opinions, quotes and credit-related and other analyses are statements of opinion as of the date they are expressed and not statements of fact or recommendations to purchase, hold, or sell any securities or to make any investment decisions, and do not address the suitability of any security.

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Secondary Contacts:Massimo Schiavo, Paris + 33 14 420 6718;
Sergei Gorin, Moscow + 7 49 5783 4132;
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Research Contributor:Igor Golubnichy, Moscow +7 495 783 4090;

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