Demand for natural gas in Europe is extremely unlikely to expand over the next decade. S&P Global Platts Analytics expects accumulated demand decline of 11.5 billion cubic metres (bcm) in 2020-2030. Although carbon dioxide emissions from gas are about 50% lower than those from coal, this is not enough to make gas compatible with Europe's decarbonization targets and with the EU Green Taxonomy. Implementing the European Green Deal and rolling out green-focused, post-COVID-19 economic recovery packages will further constrain demand growth potential for gas, as will an increasing focus on energy security and the gradual development of energy storage.

That said, S&P Global anticipates that gas will remain an important part of the European energy mix during the next decade. Most countries plan to retire very large coal and nuclear generation capacity and their energy mix will still need options that complement intermittent renewables.

Although S&P Global Ratings considers that large players rated 'BBB-' or above will be able to manage the rating pressures specific to 2020, strategic shifts have been triggered. Europe is ahead of many regions in energy transition, which increases longer-term business risks for the gas industry.

European gas producers no longer view gas as a key part of their decarbonization strategies. For example, companies such as BP, Equinor, and Total are investing in renewables; hydrogen; and carbon capture, utilization, and storage (CCUS).

Meanwhile, emerging market gas producers such as Qatar Petroleum (QP), Gazprom, and Novatek increasingly seek to monetize their gas reserves by expanding in new and growing geographic markets, or into petrochemicals. QP and Novatek are developing their LNG projects and Gazprom plans to expand its pipeline gas exports to China. Middle Eastern countries and Russia plan to expand into petrochemicals.

Many large European power generation companies are already diversified into other types of fuel and hedge the risks associated with their exposure to gas. Their growth strategies typically focus on renewables and networks, and they are making only limited investments in gas-fired power generation.

At present, regulated gas transmission and distribution companies still benefit from supportive and very predictable regulations, which underpin their resilience. Despite this, we anticipate that they will need to reduce their financial leverage if they are to maintain ratings at the current level. There are limited growth prospects for gas infrastructure, and alternative growth paths, like diversifying into hydrogen, carry technological and regulatory uncertainties. Regulatory pressures in several countries, such as Spain and the U.K., are also rising.

Europe: The World's First, Last Gas Market

The following market view comes from Ira Joseph, Head of Global Gas and Power, S&P Global Platts Analytics. S&P Global Platts is a division of S&P Global, as is S&P Global Ratings. Therefore, what follows are the sole views of S&P Global Platts, subject to its citation policy, available upon request.

Europe is a mature gas market, which is a euphemistic way of saying that its growth prospects are extremely limited. No need to blame or finger point; it's just that the market is saturated in terms of infrastructure, and gas is entering a future when it will need to stave off the competition from the new kids on the block, rather than replace what was there before it. Given this harsh reality, S&P Global Platts Analytics expects natural gas to see its topline regional demand decrease by 12 billion cubic metres (bcm)through 2030. More importantly, while gas will continue to play a central role in European energy security, Europe's storage and regasification capacity for liquefied natural gas (LNG) will take on a growing role in global security of supply, as seasonal demand swings grow in intensity.

Chart 1

Europe is still a vast gas market at over 500 bcm a year and will remain the second-largest traded market in the world after North America for decades. Even China's gas market is still only at 300 bcm. Europe will remain critical as a pricing point and is replete with infrastructure that is taking on global significance. The more LNG that Europe imports over the next decade--38 bcm more by 2030--the more gas balances in Europe will influence pricing in the rest of the world. Yet the outlook for a decline in European gas demand over the next decade is a major issue. The decline will be fairly minor in terms of volume--just under 0.3% per year--but the opportunities for gas demand growth are well past their prime. Europe is becoming a larger and larger net importer, facing unprecedented levels of competition. Save a major policy decision immediately banning coal and lignite use in power generation or an enormous gas find somewhere on the European continent, the only questions are how rapid the demand decline will be, and which sectors will suffer the most?

Most gas markets around the world are still growing due to lower prices (North America), decarbonization policies and air-quality concerns (China and India), or use as a fuel or feedstock for underlying economic growth. But even North America, which has untold volumes of low-cost gas reserves, is struggling to find a way to burn it at the lowest of prices. The added cost of moving gas to a market like Europe only makes the demand growth equation more difficult to solve. Short-term supply-side shortages (as we occasionally expect in the next 12 months) do not negate the longer-term oversupply reality relative to potential incremental demand creation.

Chart 2

The European gas market has, more or less, been essentially mature since 2005, save a few years like 2010, when abnormal temperatures caused a demand spike. Somewhat amazingly, the true tipping point demise of growth in the European gas market can actually be traced to a single moment. It began on New Year's Day in 2006, when Russia decided to cut gas flows to and through Ukraine. This prompted Europe to reconsider security of supply, and eventually, adopt the Third Energy Package, and in turn, Russia to invest in Nord Stream and TurkStream to mitigate transit risks. On that day, the renewables business we see today was born in earnest, as a legitimate case emerged in Europe for renewables as both a security and an environmental counterweight to the ever-expanding reliance on imported volumes of gas from the broader gas market.

Europe's subsequent vast investments in gas supply diversification, LNG terminals, storage, and interconnectors, as well as Russia's investments in new supply routes, have massively reduced the physical risks of a gas supply disruption. Nevertheless, customer perceptions of gas security are still shaped by memories of supply disruptions in 2006 and in 2009-2010. Meanwhile, Russia remains largely reliant on Europe, a gas market that is not growing and is more competitive than ever, for most of its gas sales. In retrospect, the incident in 2006 also became the moment that Russia understood the value of Europe in terms of security of demand as much as the moment when Europe became concerned with security of supply, and the idea of Nord Stream was born in order to avoid future Ukrainian complications. Even the Fukushima disaster five years later in 2011, which triggered an accelerated schedule for German nuclear retirements, did nothing to reverse the decline of gas use in power generation, which remains 40 bcm-60 bcm below its 2008 peak. A slower growing population, combined with policy measures promoting renewables and more efficient electricity use, undermined the ability of gas to find its mojo once again.

At its core, the issue for gas will remain that the cost of importing from other countries and regions is rising, while the cost of renewables and batteries are falling, and coal prices are chronically weak. In particular, LNG is the costliest form of incremental gas supply trying to compete in the most price-sensitive form of demand: power generation. Europe is in the process of replacing low-cost gas supply from the U.K., the Netherlands, and Norway with either lower-cost gas supply from Russia or much higher-cost gas supply from the LNG market. Neither option is an optimal solution: the former presents a political problem and the latter an economic one. Imported gas, particularly LNG, does not compete well with the emergence of several alternatives in power generation for most hours of the day. As renewables continue to scale, gas risks seeing its position deteriorating as an intermittency solution. More cost-effective batteries are emerging, and Europe can still rely on more traditional sources of flexibility, such as hydro storage and power interconnectors.

Does gas have a long and sustainable role in the European energy mix? Absolutely it does. The role of gas as a stable and flexible source for power generation cannot currently be challenged from either a commercial or operating perspective, although predators are certainly at the gate. The flexibility of gas use to meet hourly loads was a primary driver in its ability to overtake coal use in the prior generation. That conquest is not entirely complete, even as other competitors to replace coal attempt to outflank gas. The gas-to-coal switching channel still provides another 75-125 million cubic meters per day of sustainable demand potential, and most of it can be generated using existing gas-fired infrastructure, even as the risk grows of committing capital to a new combined cycle gas turbine (CCGT) in this day and age. Additionally, large retirements of nuclear plants, because of age or political opposition, does create room for gas units to operate. These large retirements are taking place, while the EU is targeting a fast ramp-up of hydrogen production, especially from renewable sources.

Chart 3

Europe's greatest gas asset going forward will be its storage capacity, which has rapidly evolved from a regional to a global asset. Once again, the 2006 disruption played a central role, as European storage capacity roughly doubled thereafter as a response to the greater perceived risk to imported gas that was emerging. Now Europe is not only storing gas for Europe, but also for Asia and every other LNG-importing country with a winter demand peak and nowhere to put the LNG during the summer. The additional availability of Ukraine's sizable 31 bcm of storage capacity for broad commercial use significantly boosts the relevance of Europe's storage assets.

Platts Analytics' 10-year forecast shows gas demand dropping another 12 bcm (0.3% per year) by 2030 in total, including a 12 bcm (0.45% per year) decrease in northwestern Europe. The drop in Europe will emerge as a 65 bcm drop in production within the region--Norway, the Netherlands, and the U.K.--will need to be replaced by higher imports, either from within Europe or abroad. Higher imports mean higher delivered costs, which will cut into demand due to competitive threats in the power sector and drive greater efficiencies in the local distribution zone (LDZ), where residential/commercial demand is the primary driver. LDZ demand will also drop if normal weather conditions for winter continue to warm.

As my friend Patrick Heren, Europe's revolutionary pricing architect, has so eloquently put it, no one speaks for gas. It is the foster child of fossil fuels; politically and economically, it is an orphan. In Europe it used to be broadly run by Big Oil, but around the Millennium it was sold off to Big Power. And Big Power is now in the grip of Big Green and doesn't necessarily want gas living at home much longer.

Gas In Europe Provides A Short Bridge

S&P Global Ratings still views gas as a bridge fuel, and a part of the energy transition process. However, in Europe, the bridge could be shorter than in other regions. Although greenhouse gas emissions from natural gas power stations are lower than those from coal-powered stations, unabated gas (that is, fossil gas used without carbon capture or storage technology) is not compatible with the EU's long-term decarbonization goals. Under the EU's Green Taxonomy, gas is an intermediary solution only, because it is a fossil fuel and emits more than 100g of carbon dioxide per kilowatt-hour.

The EU has created an economic stimulus plan to help European economies recover from the COVID-19 pandemic, comprising a Next Generation EU Fund and additional funding at the national level. Of the $750 billion fund, 30% focuses on sizable financial support for climate-friendly projects, especially renewables, energy efficiency, and hydrogen.

Europe also leads the way in environmental, social, and governance (ESG) investment. European exchange-traded funds already held ESG assets of €1,663 billion in 2019, and PricewaterhouseCoopers LLP projects that this will increase to €5.5 trillion by 2025. Investor pressure increases the cost of capital for projects related to fossil fuels.

Nevertheless, we believe gas will be needed to offset the large mandatory retirements of coal-fired and nuclear power generation capacity. In 2019, 21.5% of the EU's power generation fuel mix came from gas. The exact amount varied widely from country to country. In the Netherlands, the U.K., and Italy, gas provided over 40% of power, but only 15% in Germany, and a mere 9% in coal-dependent Poland.

Replacement options are not ready yet

The potential for renewable energy varies across Europe. Existing gas-fired facilities offer a lower-cost option than investing in new nuclear facilities, and a lower-carbon option than coal. The shortage of energy storage solutions currently makes gas the key "insurance policy" against renewable intermittency, although future developments in energy storage capacity and technology could change this.

Hydrogen is a promising energy storage option, but the EU target for green hydrogen is still very low at 6 gigawatt (GW), in the context of Europe's energy system. We don't expect hydrogen to offer a new life for gas because Europe's hydrogen policy explicitly favors green hydrogen, produced via water electrolysis using renewable electricity, over blue hydrogen, produced from methane. That said, the recent lockdown shows that existing grids can probably cope with a higher share of renewables.

Chart 4

Gas demonstrated extreme price volatility in 2020. Title Transfer Facility (TTF) spot prices fell below $1.5 per million British thermal units (mmbtu) in May-June, but reverted to about $5/mmbtu in October, as the heating season began. A massive increase in LNG capacity was commissioned in 2019, making the global gas markets oversupplied, even before the lockdown. Thanks to its location and ample storage capacities, Europe often acts as a swing market.

Chart 5

The Pressures Of 2020 Herald Longer-Term Problems

For most producers, gas remains generally supportive to their business risk profile, because gas provides diversification. Gas prices have become delinked from oil prices, and peak gas is likely to be further away than peak oil. In addition, LNG often allows producers to have longer-term contracted volumes, even if it does not guarantee stable revenue.

Chart 6

European gas producers increasingly look at diversification into renewables

Until recently, many producers viewed gas as part of a global decarbonization solution. They invested in gas, especially LNG, to match the global growth in gas demand. Given increasing uncertainty about the trajectory of global gas demand and future gas prices, many are now changing strategy. BP, Equinor, and Total, among other large global gas producers are now aiming to become diversified energy companies through investments in renewables. They also want to establish early positions in hydrogen and CCUS.

For example, BP's new strategy is to achieve net zero emissions by 2050 or sooner. It is increasing its investments in sustainable energy and its energy partnerships and using active portfolio management to reduce hydrocarbon production. This, combined with stopping exploration in new countries, should result in a 40% hydrocarbon production decline by 2050. Over the next decade, BP aims to reduce the carbon intensity of its operations by 30%-35% and build about 50GW of renewable capacity. Equinor aims to make its operations carbon-neutral by 2030. Its interim goals are to have 4GW-6GW of renewable capacity by 2026 and 12GW-16GW by 2035.

Many gas producers are also looking at CCUS opportunities. For example, Equinor has a CCUS project in the North Sea. Currently, policy support for CCUS is less pronounced than for renewables, but we anticipate that attractive financial mechanisms may emerge in the future because CCUS are important for long-term decarbonization.

Although many large exploration & production (E&P) players have cut their oil and gas capital expenditure (capex), they continue to invest in renewables. As the price of oil and gas has fallen and investment in renewables attracts strong policy support, the difference between potential returns on oil and gas projects and those on renewables is likely to shrink.

Today's investments in both gas and renewable developments could perform for years, even decades. Therefore, the nature of and balance between these different investments is critical. We consider a range of energy activities is likely to be more resilient over time, even if higher returns might be achieved at different times from a more-focused portfolio. In reality, for many years, the cash generated from oil and gas activities will fund or support other investments. Nonetheless, players will need to focus on low-cost, flexible developments to minimize the risk of holding stranded assets, if the energy transition advances rapidly over the coming decade.

Russian and Middle Eastern producers look at growing Asian markets

Russian and Middle Eastern gas producers have tended to focus on monetizing their massive gas reserves by targeting markets that have higher demand growth potential, such as LNG, gas pipeline export to Asia, and petrochemicals. Although the European gas market is set to stagnate, gas demand in China and other Asian countries is set to grow.

The Russian Energy Strategy aims to increase pipeline gas exports to 255 bcm-300 bcm a year, from 200 bcm in 2018 and LNG exports to 108 bcm-189 bcm a year, mostly to Asia-Pacific. Russia's largest capex projects across all sectors include Novatek's Arctic LNG-2, an LNG production project estimated to cost $21.3 billion; Gazprom's LNG export and chemical project in the Baltic port of Ust-Luga, which is estimated to cost Russian ruble (RUB) 750 billion and is being built through a 50:50 joint venture; and Sibur's new petrochemical plant. Novatek's unique location in the north of Russia makes it possible to ship LNG to both Europe and Asia via the Northern Sea Route.

Gazprom's CEO has unveiled plans to increase exports to China to 130 bcm. That said, we view these plans as very ambitious, long-term, and subject to massive capex. The first stage of the Power of Siberia project, commissioned in December 2020, involves a 2,200 km pipeline from the Chayanda gas field in Eastern Siberia to China. After that, considerable investments will be needed to build a 800 km pipeline link to the Kovykta gas field, construct the Amur gas processing plant, and ramp up exports to the 38 bcm of already-contracted volumes by 2024. And 38 bcm is far short of the 130 bcm target.

Expanding exports further would require a new multibillion pipeline from Gazprom's core production area in Western Siberia to China. In our view, this will only be possible if Gazprom manages to sign a new offtake contract with China. Therefore, for now, we expect Europe to remain the key market for Russian gas. Similarly, large Middle Eastern producers like QP are aiming to expand their LNG production and making vast investments in domestic petrochemicals.

On the ESG side, Russian gas producers Gazprom and Novatek focus on reducing emissions from their core operations, rather than on making a shift away from fossil fuel entirely. They will also play a major role in Russia's hydrogen strategy, which has a 2 million metric tonnes target by 2035.

Several Outlooks Have Turned Negative

In the short term, the challenge for many gas producers will be to restore their credit metrics post-2020. Our ratings analysis considers multiyear averages. Thus, a rebound in credit measures in 2021 takes on greater important.

The record low prices of mid-2020 were below full costs and even below marginal costs for most gas producers. Gas storages were already full by year-end 2019, and the pandemic also hit sales volumes through demand destruction. Because prices were very low, Gazprom cut its exports to Europe and many LNG producers faced cargo cancellations. Financial metrics were also hit by the oil price collapse and decline in liquids volume on the back of lockdowns, the economic recession, and changes in demand patterns. As the metrics fell below the level we consider compatible with our ratings, we revised to negative our outlooks on a number of players, including Shell, Equinor, and Gazprom. We will be monitoring how quickly the metrics recover in 2021-2022 to determine the effect on ratings.

Chart 7

Financial policies make a difference

All the European gas producers have announced capex cuts of up to 30%. Some, like Shell and BP, also cut dividends. Other factors that may affect gas producers credit metrics include:

• The significant price recovery since August 2020. TTF prices rose to around $5/mmbtu in October-November from below $1.5/mmbtu in May, enabling most European producers to cover their costs.
• Financial headroom before the crisis. This was stronger at some producers, such as Equinor and Novatek.
• Diversification into oil. Gas prices are essentially decoupled from oil. It is particularly relevant for those producing associated gas. If liquid prices cover joint production costs, the cost of producing associated gas essentially falls to zero. Oil prices have recovered, reaching a level close to many producers' full costs more quickly than gas prices did.
• Contract structures. Legacy oil-linked contracts or forward-linked prices enable many gas producers to realize gas prices well above the spot price. For example, Gazprom's average export price to Europe and Turkey in the second quarter of 2020 was $110 per million cubic meters (/mcm)--the spot price at that time was well below $100/mcm. Management's guidance for full 2020 is $133/mcm. In 2019, only 33% of Gazprom's exports were under spot prices. The remainder comprised 17% oil-linked, 16% hybrid, 23% forwards, and 11% electronic sales platform and trading.
• Competitive costs and tax hedges. For example, we understand that Equinor's cost of gas delivered to European markets is about $1.6/mmbtu. We also estimate that Gazprom's full cash costs to Europe are about $2.1-$2.8/mmbtu, and its marginal costs are even lower, closer to $1.6/mmbtu, depending on the destination. Equinor's high corporate tax at 78% and Gazprom's 30% export duty act as partial natural hedges. Novatek's management estimates all-in costs for its Yamal LNG at $1.50-1.75/mmbtu for Europe.
• Regulated or quasiregulated domestic prices (for example, in Russia and Azerbaijan). Although regulated domestic prices in Russia have historically been well below export prices at about $60/mcm, they still cover operating expenditure, and the 2020 fall in export prices made domestic netbacks relatively attractive, when adjusted for transportation costs and export duty. Domestic sales remain low-margin, but profitable, and provided stable EBITDA contributions for Gazprom, Novatek, and Russian oil companies.
• In addition, we assume that national players such as Gazprom will receive ongoing and exceptional government support, which limits rating downside for these entities.

Utilities Ratings Are Supported By Diversification

Large integrated utilities had already moved away from significant exposure to gas operations because of reduced merchant gas activities. Increasingly, they prefer to expand their power network to the detriment of gas. Most rated large European utilities are diversified by fuel type and integrated. Their high EBITDA contribution from regulated and service activities helps offset the high volatility of gas-fired generation on their business risk profiles (see charts 1, 2, and table 1). The rated companies most exposed to gas-fired generation are Engie, Uniper, Fortum, A2A, Edison, and Naturgy. Many players hedge a high proportion of their power generation. For example, Uniper hedges 100% of 2020 production and 55% of 2021; Engie hedges 80% of 2020 production and 54% of 2021. Another alternative is to enter into long-term gas purchase contracts. This improves profit visibility, even if it sometimes locks-in unfavorable prices for electricity or gas under legacy contracts.

In European markets like the U.K. and France, gas-fired generation can receive capacity payments, but typically, their contribution to EBITDA is quite small at 5%-10%). Where companies are expanding their regulated network activities in Europe and abroad, they generally focus on power networks, rather than gas infrastructure (examples include Enel or Iberdrola). Some diversified utilities--including Engie, Naturgy and SSE--have also reduced their exposure to gas infrastructure as part of their asset rotation policy, either to lock in high valuations or to focus on faster growing segments.

Table 1

Growth Prospects Are Flagging

We believe gas generation growth prospects have been most affected by the market developments. Although utilization rates may remain high in the coming years, supported by the phasing out of coal and nuclear power, Europe is unlikely to build much new CCGT capacity. The economics of gas generation assets will gradually weaken as carbon prices rise and the cost of renewables falls further.

Much of the 2019-2020 uptick in European gas-fired generation comes from higher utilization of existing gas-fired capacity. The record low gas prices, combined with relatively high carbon dioxide prices, created an economic advantage for gas compared with coal. For the same reason, the pandemic-inspired decline in electricity volumes hit coal harder than gas.

At this stage, we don't expect to see massive new investments in gas infrastructure in Europe in the next five years. There has been massive construction in previous years, so that interconnectors, underground storage, and LNG terminals already support a sufficient degree of diversification and security of supply, in our view.

New investments in EMEA gas-fired generation remain limited. There were only a few projects, such as the 0.7 GW CCGT built in Italy and several relatively small coal-to-gas switching projects that have short payback times in northwestern Europe. For most rated companies, their strategy is to focus on growth in renewables generation. Companies aim to avoid having stranded assets, given Europe's decarbonization focus, technology development, and the weakening in clean spark spreads as gas prices rebound from the record lows of mid-2020.

Regulation Is Supportive But Tightening

Decarbonization targets mean uncertain times for gas, particularly compared with electricity networks. Its current monopolistic position and the very slow decline in natural gas consumption still provides gas generators with earnings stability for the coming decade. These factors support the credit ratings, for now, but if long-term uncertainties are not clarified, companies will struggle to maintain their current ratings without reducing their financial leverage.

For regulated gas utilities in Western Europe, solid and predictable regulatory regimes remain the key factor that supports ratings. Regulated gas utilities in Europe have generally proved resilient to the downturn triggered by the pandemic. The regulations ensured that they had adequate coverage of operating expenditure as well as capex and, in most cases, also protected them from volume swings. Therefore, we typically demand less from them in terms of leverage metrics, and use low or medial volatility tables to assess their financial risk profile.

That said, in the longer term, uncertainty about the role of gas in each country's energy mix poses risk for gas infrastructure. We see weaker growth prospects and a higher risk of stranded assets materializing over time. We believe this may well start to weigh on regulatory returns and investments in gas over future regulatory periods.

Regulatory pressures have already emerged in several countries, leading to weaker projected financial metrics and weighing on outlooks. For example, recent regulatory resets in Spain and in the U.K. led to lower remunerations for gas utilities because regulators do not see the need for higher capex and because they allowed for lower interest rates. This has already triggered outlook revisions for several European gas utilities, including Wales & West Utilities' notes and Scotia Gas Network in April 2020.

Regulated gas utilities in Western Europe are increasingly looking to reinvent their business models by growing into activities aligned with the EU decarbonization focus, such as hydrogen. That said, this is an area subject to technological uncertainty and requires the adaptation of regulatory frameworks. It also involves massive capex and will still result in some stranded assets, given that in many cases the routes needed for hydrogen and for methane are different. Therefore, this switch could still heighten future business risk.

New Infrastructure Projects Face Risks

Several large European gas infrastructure projects in progress still face uncertainties. Completion of NordStream 2 will largely depend on U.S. sanction risks, for instance. That said, the pipeline was 94% complete by the end of 2019, meaning that most costs are sunk. Even if NordStream 2 is not completed, we don't see any material risks for gas flows to Europe from Russia and we expect the project's 100% shareholder Gazprom and European energy companies Shell, Engie, Uniper, and OMV (which provided debt funding for it) to be able to manage the rating impact of a failure to finish building the pipeline. Broad sanctions on large parts of the gas value chain are not part of the base-case scenarios in our ratings analysis for the European energy sector.

EP Infrastructure's subsidiary Eustream, a gas transit operator in Slovakia, gains revenue visibility--and therefore rating support--from its lucrative legacy long-term ship-or-pay contracts. These include a contract for 50 bcm per year, until 2028. That said, we don't necessarily expect such contracts to be renewed at the same lucrative terms when they expire. The risk of contract renegotiation remains key to our analysis, given the long-term uncertainty about gas transportation volumes and potential competition with NordStream 2.

The most recent new gas pipeline into Europe, Trans-Adriatic Pipeline (TAP), was completed in November 2020. It brings gas to Italy, Bulgaria, and Greece from Azerbaijan's Shah Deniz field. We expect other gas pipeline projects already in progress to be completed. These include the Baltic pipeline, which is due to complete in October 2022, and several interconnectors. The Baltic pipeline will carry 10 bcm to Poland from Norway.

Both TAP and the Baltic pipeline are relatively small in terms of impact on Europe's energy security, but could influence gas pricing and competition in specific countries, such as Italy or Poland. The recent military conflict between Azerbaijan and Armenia in Nagorno-Karabakh highlights TAP's political risks. Although oil and gas assets are relatively remote, the pipeline that eventually feeds TAP runs only 30-40 kilometers from the conflict zone. We understand that the conflict has not yet affected oil and gas assets or operations. Despite the ceasefire in November 2020, some political uncertainty remains. We forecast that TAP will make only a limited EBITDA contribution because of the high cost of gas and its gradual ramp-up.

Gas-Supportive Policies Boost Utilities' Margins In CIS

In contrast to Western Europe, in the Commonwealth of Independent States (CIS), governments' energy policies are generally supportive of gas. Therefore, we expect gas-fired generation to remain profitable and stable. Nevertheless, growth potential for gas in Russia is limited by existing overcapacity and stagnant energy demand. The following rated companies in the region are heavily exposed to gas:

• Mosenergo, a Russian power generating company (almost 100% of generation volumes);
• TGC-1, a regional power company in northwest Russia (two-thirds of generation volumes);
• Georgian Oil and Gas Corporation (100% of generation volumes); and
• Azerenerji, an electrical power producer in Azerbaijan.

For European companies operating in Russia (such as Fortum and Uniper), the key risk relates to foreign exchange volatility (the ruble weakened in 2020). Fortum and Uniper have a material presence in Russia of about 25%, including gas-fired power generation.

In the CIS, we view gas as positive because it doesn't carry near-term exposure to regulatory risks or to gas price volatility. In Russia, gas-fired generation benefits from lucrative capacity supply agreements (CSAs). About 15%-20% of revenue at TGC-1 and Mosenergo comes through CSAs, which guarantee return on historical investments.

Domestic gas prices are also stable as Russia's largest producer, Gazprom, is regulated, electricity prices are less volatile than in many large European markets, and competition with renewables other than hydro is limited. Even though capacity revenue is set to decline as first-round CSAs expire and the second round of CSAs will be considerably smaller, solid EBITDA has enabled Mosenergo and TGC-1 to repay most of their legacy debt. This means that funds from operations (FFO) to debt is above 60% for both companies.

Russia's Energy Strategy, approved in 2020, aims at 2%-5% growth in domestic gas consumption by 2030, compared with an increase of up to 3% in primary energy consumption. We expect investments in gas-fired generation to focus on modernization, increasing the efficiency of the existing fleet, and import substitution for turbine manufacturing. There is unlikely to be significant capacity expansion. Georgia is also a gas-supportive environment because the government promotes construction of all types of new electricity generation, to reduce dependency on energy imports and ensure security of supplies. As a result, GOGC's gas-fired plants enjoy attractive power sales agreements that have stable U.S. dollar-denominated prices or guaranteed returns on investment. These agreements resemble some of the Western European companies' arrangements for renewables and have contributed 70% of GOGC's EBITDA since Gardabani-2 was commissioned in early 2020. The company's operations remain resilient--its main risk is now related to refinancing of its 2021 bond.

Chart 8

Chart 9