SECTOR IN-DEPTH capturing opportunities of decarbonization … · 2017. 11. 13. · [email protected] Mariko Semetko 81-3-5408-4209 VP-Sr Credit Officer [email protected]

INFRASTRUCTURE AND PROJECT FINANCE

SECTOR IN-DEPTH2 November 2017

Contacts

Natividad Martel,CFA

212-553-4561

VP-Senior [email protected]

SwamiVenkataraman, CFA

212-553-7950

Senior Vice [email protected]

Jillian Cardona +1 212 553 4351Associate [email protected]

Ivy Poon 852-3758-1336VP-Senior [email protected]

Graham W Taylor 44-20-7772-5206Sr Credit [email protected]

Toby Shea 212-553-1779VP-Sr Credit [email protected]

Mic Kang 852-3758-1373VP-Senior [email protected]

Abhishek Tyagi 65-6398-8309VP-Senior [email protected]

Mariko Semetko 81-3-5408-4209VP-Sr Credit [email protected]

Stefanie Voelz 44-20-7772-5555VP-Sr Credit [email protected]

Regulated Electric and Gas Utilities and Networks - Global

Prudent regulation key to mitigating risk,capturing opportunities of decarbonizationRegulated electric and gas utilities and networks (collectively “regulated utilities”1) facerising credit risks from decarbonization initiatives. The sector is central to countries' ability toachieve their nationally determined contributions (NDCs) under the Paris Agreement. Powergeneration is a top contributor to carbon emissions, representing at least 25% of emissionsin 66 countries. But importantly, the sector is the main conduit for the implementationof decarbonization initiatives because it is the primary source of carbon-free energy viarenewables, nuclear and hydro power. Reducing fossil fuel use, including in transportationand residential heating, could lead to electrification of these sectors. Because utilities areprice-regulated, prudent regulation is the key driver of utilities' ability to mitigate risk andcapture opportunities from carbon transition.

» Policy risk varies widely with business mix, fuel use and country NDCs. Whileall regulated utilities face risk from carbon transition, those that own generation aresignificantly more exposed. Among countries where we rate generation-owning utilities,the sector's share of total emissions varies from as high as 55% (South Africa) to as lowas 5% (Uruguay), reflecting the relative size of the sector and fuel mix. In assessing carbontransition risk, we focus on the magnitude, timing and pace of reductions targeted, theform regulations take, broader national energy policies and the influence of market forces.

» New technologies and changing customer preferences create risks, opportunities.For utilities, the rise of disruptive technologies and changing customer preferencesare closely intertwined. Emerging technologies present utilities with risks as well asinvestment opportunities. The greatest risk would arise in a scenario (unlikely at present)where a combination of distributed generation and energy storage eventually becomescompetitive and fundamentally disrupts utilities' monopoly, cost-plus business model.

» Prudent regulation is critical in mitigating financial risk for the sector. The utilitysector has a median rating of Baa1 vs Ba3 for nonfinancial corporates and a 10-yearcumulative default rate that is 11x lower. Utilities are strong credits because they areregulated monopolies allowed to recover costs and earn an authorized return. Regulatoryactions have an overwhelming effect on their financial performance: not only willregulators direct the carbon policies utilities will implement; they also set the price utilitiescan charge customers. So while carbon transition offers growth opportunities, it exposesutilities to potential under-recovery or stranded assets. We believe regulators will supportrecovery of most carbon costs, though the mechanisms remain undefined or untested incertain jurisdictions, and affordability considerations may constrain cost recovery.

http://www.surveygizmo.com/s3/1133212/Rate-this-research?pubid=PBC_1082285

MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE

Regulated utilities, regulated networks and unregulated utilities

This report covers only companies rated under two different methodologies: regulated electric and gas utilities (utilities) and regulated electricand gas networks (networks). Companies rated under both methodologies are subject to some form of price regulation by a national orregional government, either directly or through a regulatory body. This oversight, necessitated by the natural monopoly they enjoy, allows thecompanies to collect revenue based on their cost of service, usually with a built-in return on capital.

Moody's also has a different methodology, unregulated utilities & unregulated power companies (unregulated utilities), applicable tocompanies whose revenues and profits depend to a significant extent upon competitive wholesale commodity markets and/or competitiveenergy services businesses. Carbon transition risks of these companies have been addressed in “Global Unregulated Utilities and PowerCompanies - Carbon Transition Brings Risks and Opportunities”

The different methodologies reflect varied approaches to “deregulation” adopted by different countries. The utility value chain consists of fourcomponents: (i) Generation, (ii) Transmission, (iii) Distribution and (iv) Energy Supply, including services and customer relationship. Individualcompanies may provide one, a few or all of these services.

In all of the markets we cover, the transmission and distribution (T&D) elements are subject to some form of price regulation. In someregions, however, generation, supply, or both generation and supply, are also price-regulated, while in others generation and supply arecompetitive (which we term “unregulated”). The map below shows countries where Moody's rates utilities, and identifies whether only theT&D elements or the whole value chain is price-regulated. Countries and regions shown in blue have vertically integrated regulated utilitieswith the entire value chain subject to price regulation. Countries shown in green have regulated transmission and distribution companiesalongside unregulated generation or supply companies.

Yet other types of utilities exist in the US that are not investor-owned but are instead owned by states or municipalities (public power) or byutility customers themselves (cooperatives). Moody's rates such utilities under separate methodologies not addressed in this report.

This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page onwww.moodys.com for the most updated credit rating action information and rating history.

2 2 November 2017 Regulated Electric and Gas Utilities and Networks - Global: Prudent regulation key to mitigating risk, capturing opportunities of decarbonization

https://www.moodys.com/research/Global-Unregulated-Utilities-and-Power-Companies-Carbon-Transition-Brings-Risks--PBC_1030584

https://www.moodys.com/research/Global-Unregulated-Utilities-and-Power-Companies-Carbon-Transition-Brings-Risks--PBC_1030584


Regulated utilities are a major focus of carbon transition policies

Utilities are a key focus of most countries' NDCs under the Paris climate agreement. According to the World Resources Institute, theutility sector (electricity and heat) accounts for 34% of global carbon dioxide (CO2) emissions, at least a third or more of emissionsat the top five CO2 emitting jurisdictions (China, US, EU, India and Russia) and at least 25% of CO2 emissions in 66 countries. Exhibit1 shows the contribution of the power and transportation sectors to the total greenhouse gas emissions of selected countries withregulated generation assets. Electricity and heat are, in most of these markets, the largest contributors to emissions.

Separately, the utility sector is a focus of decarbonization efforts because it is also the primary source of carbon-free energyvia renewables, nuclear and hydro power. Decarbonizing the broader economy usually implies electrification of sectors such astransportation and heat, which creates growth opportunities for the utility sector. Utilities also own the networks that will integratedistributed renewables and enable electrification of other sectors.

Exhibit 1

The power and transportation sectors are big contributors to greenhouse gas emissions in many countriesGreenhouse gas emissions by sector in selected countries with regulated power generation (2014)

40% 37% 35%

48% 51%56%

43%

29% 26% 24%

38%

50%56%

50%

22%

3% 6%

7%

27%

8%

16%14%

10%

23%

24%21%

17%

21%

19%16%

14%

12%

10%

35%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

China UnitedStates

India Japan Korea, Rep.(South)

South Africa Saudi Arabia Canada Mexico Indonesia Malaysia Israel Qatar Bulgaria Oman Uruguay Costa Rica

Electricity/Heat Transportation Other

Note: Countries shown here are those where Moody's rates regulated utilities that own generation. Generation in most EU countries is deregulated and hence not shown here.Transportation is also shown because its electrification represents a potential growth opportunity for utilitiesSource: World Resources Institute's CAIT Climate Data Explorer. 2014.

From a credit perspective, utilities are increasingly exposed to carbon transition risks because there are large and material costs toconverting the infrastructure from the existing generation fuel mix to a smarter, more environmentally friendly and flexible generationmix. Moody’s assesses carbon transition risk using our central emissions scenario consistent with the NDCs agreed to as part of theParis Agreement. This scenario is forecast to result in global warming of 2.5°C–3.0°C above preindustrial levels2. Although the NDCscenario is insufficient to limit global warming to less than 2°C, as committed to under the Paris Agreement, it represents a plausiblecentral scenario given its near-universal adoption and the current policy commitments of national governments, as well as technologytrends.

We have developed a framework to evaluate the credit impact on all sectors under three key transmission mechanisms: (i) policy andregulatory uncertainty, (ii) demand substitution and changes in consumer preferences, and (iii) risk of technological shocks.3. The risksassessed through this framework are directly incorporated into our scoring of the rating methodology factors (see Exhibit 2). In the caseof regulated utilities, any credit impact from carbon transition is ultimately a result of a regulator's decision to delay or deny recoveryof costs. We view the uncertainties associated with the tariff setting framework also as a part of policy and regulatory uncertainty.



Exhibit 2

Rating Methodology scorecards capture the key carbon transmission mechanisms

Note: Moody's scores a number of sub-factors within each methodology to capture the impact of the transmission mechanisms. See Appendix C for details of the sub-factors.Source: Moody's Investors Service

Carbon transition risks' potential impact on ratings

Credit ratings for regulated electric & gas utilities and networks (regulated utilities) express opinions on the relative risk of default and creditloss. As such, ratings incorporate our forward-looking view of all material risks, including carbon transition risks. Since our current view ofcarbon transition risks for the sector and each company is already reflected in our ratings, publication of this report has no immediate impacton ratings.

Carbon transition risks are considered as part of our overall integrated analysis of credit risk for the regulated utilities sector and for eachcompany in the sector. As is the case for most risks that affect credit quality, carbon transition is not scored on a granular level in regulatedutilities rating methodologies. Examples from the multitude of other important risks that are not scored individually in methodologyscorecards include management; labor relations; litigation; changes in technology, customer preferences, and market structure; supply anddemand dynamics; and competitors’ strategies. Our view of the impact of such risks, including carbon transition risks, are incorporated intoratings through impacts on broad factors in the methodology scorecards and in our additional assessment of outside the scorecard ratingconsiderations.

Regulated utilities industry rating methodology scorecards are included in the Appendix (Appendix C). These show scorecard measures thatwill be affected by carbon transition which, for example, could lead to lower scoring for factors such as regulation, diversification, ability torecover costs, financial strength and leverage and coverage. For reasons that include false precision, we do not publish scorecards extendingmultiple years into the future. However, ratings are intended to be forward-looking and to incorporate relevant credit considerations as farinto the future as possible. When we believe that an emerging risk is highly likely to result in weaker scorecard outcomes in the future, weincorporate this expectation into ratings at the present time. Consistent with this long-standing approach, when our evolving understanding ofthe credit impacts of carbon transition leads us to believe that it is highly likely that scorecard outcomes for a particular issuer will materiallyworsen, we expect to incorporate this into its rating well before deterioration is fully evident in the issuer’s financial and operating results.



Exhibit 3 positions utilities along a carbon risk spectrum based on the factors considered in the three transmission channels anddiscussed in greater detail below. It summarizes the key characteristics of both generation-owning and network utilities that are majordrivers of carbon risk. The risk modifiers shown to the right help move the utilities' positioning to the left or the right along the carbonrisk scale.

Exhibit 3

Carbon transition risk spectrum

Source: Moody's Investors Service



Business mix, fuel mix and carbon reduction pathway will determine utilities' exposure to de-carbonization policy

Key factors in assessing the potential impact of policy and regulatory uncertainty

» Degree of uncertainty over the magnitude, timing and pace of carbon reductions imposed on regulated utilities, as well as how theymay vary across different countries;

» The utilities' business mix is key in determining their carbon exposure, vertically integrated utilities are more exposed than distributionand network companies;

» For generation-owning utilities, the fuel mix drives exposure to policy risk;

» Market forces, including the falling costs of renewables and private sector sustainability goals, also drive decarbonization.

The transition to a low-carbon electric grid creates risks for all utilities, chiefly centering on the potential for stranded assets4 andaffordability concerns if tariff increases are significant and hence politically sensitive. However, business mix is a key driver of thecarbon exposure faced by utilities. Regulated utilities that own generation have significantly more carbon risk than those without.

For generation-owning utilities, the fuel mix is a major determinant of carbon exposure. In some smaller countries such as Costa Ricaand Uruguay, the power sector is largely decarbonized while larger power markets in China, India, South Africa and Indonesia havea significant share of coal generation (see Exhibit 4). NDCs in many Asian countries anticipate a continued large share of coal in thefuel mix to support growing demand. Hence, coal plants in these countries are less exposed to carbon risks (at least until NDCs aretightened further) than those in the US and EU, which have seen widespread shutdowns of coal plants and/or carbon cap-and-traderegimes. The fuel mix may also vary between utilities within a single country.

Natural gas plants may also come under pressure for retirement over the long term as countries increase the required share of powerfrom renewables and the economics of battery storage become more compelling. For example, eight US states target 80% to 100%renewables by 2050, potentially putting natural gas plants in these states at risk.

Exhibit 4

The power sector's fuel mix, a major determinant of carbon exposure, varies from country to countryUtility sector fuel mix in countries with regulated generation (2015)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

SouthAfrica

India China Indonesia Israel Bulgaria SouthKorea

Malaysia Japan UnitedStates

SaudiArabia

Mexico Canada Oman Costa Rica Qatar Uruguay

Coal Oil Gas Biofuels Waste Nuclear Hydro Geothermal Solar Wind

Source: IEA

Utilities that do not own generation face different, but generally lower, risks in relation to carbon transition. Globally, transmission anddistribution (T&D) utilities and networks are confronted with increasing investment needs as well as changing operating paradigms inaccommodating the growing share of renewables and in creating a “smart grid”. While improving the future resilience of the grid, a



credit positive, this investment brings execution risk and weighs on credit metrics, besides potentially creating affordability concerns.In addition, small scale generation, self-supply and energy efficiency may decrease volumes significantly and challenge the large scalenetwork model.

Decarbonization is raising questions about the long-term future of gas distribution utilities in some developed countries where policiesseek to move residential heating away from natural gas towards electricity. For example, the Netherlands intends to end the use of gasby households by 2050. Although legislation to achieve this is yet to be enacted, gas transmission tariffs already indicate a reductionin allowed revenues of around 20% in 2021 compared with 2016, due to a combination of higher efficiency targets, a lower allowedreturn and falling investment requirements for the gas grid. The US state of Washington has adopted a rule that would require naturalgas distributors to reduce carbon emissions from the gas they supply by 1.7% annually until 2035. The rule is currently being challengedin court.

Utilities face varying carbon reduction pathways in terms of the magnitude, timing and pace of carbon restrictions. The ParisAgreement has helped to improve visibility in this regard. Still, governments across the world will need to translate Paris commitmentsinto actionable policy programs before their impact can be evaluated. A rapid transition, even with clearly stated objectives, posesexecution risks: the utility sector is fundamentally slow to change given the critical importance of reliability and the centrality of thesector to the economy.

Utilities that engage in the process early and comprehensively with regulators will be better positioned to manage the transition.For example, some UK gas networks are exploring alternative uses for their networks, such as transporting hydrogen as a heatingfuel. A deliberate and measured approach becomes even more important for utilities operating in regions that are early movers. Forexample, we downgraded Hawaiian Electric Company (HECO)'s senior unsecured rating to Baa2 from Baa1 over concerns that HECOwill continue to face significant challenges in transforming its generation base to 100% renewable sources.

Countries' NDCs are also influenced by broader national energy policies which may have other objectives besides decarbonization.Prominent among such considerations is the future of nuclear power. Japan lost 29% of its power supply following the March 2011Fukushima accident when all of the country's nuclear plants were shut down. Progress on restarting nuclear reactors has been slow,with only five of 42 reactors operating today. This loss has been replaced by fossil generation (largely natural gas) that has increasedemissions. Japan's NDC calls for nuclear plants to provide 20-22% of total supply by 2030. If Japan finds it difficult to return morenuclear plants to service, it is possible that the country will build new coal plants, since imported natural gas is much more expensive.South Korea and US state of California are adopting a contrasting nuclear policy of shutting down their nuclear plants when theircurrent license period expires, due to safety concerns. Yet another policy consideration revolves around coal mining and related jobs.Indonesia, South Africa and US states such as Kentucky, West Virginia and Wyoming have a substantial coal-mining industries andrelated jobs. Coal-fired plants in these regions may enjoy political support that could reduce risks, at least in the short to medium term.

Market forces can also affect carbon risks independently of policy. For example, we expect that US withdrawal from the ParisAgreement, and the consequent absence of a federal carbon policy, will only have a limited impact on decarbonization. The economicsof natural gas and renewables, state and local policies, private-sector momentum—many large corporations are targeting a 100%renewable mix in their supply—and investor focus on environmental risks are combining to support strong growth in US renewablesand continued decarbonization.5

How policy risk is captured in our rating methodology scorecard

The business mix determines whether the regulated utility or network methodology is applicable. Further, in the regulated utilitymethodology, generation-owning utilities need to meet more stringent financial benchmarks under Factor 4, “Financial strength”, than T&Dutilities. For a generation-owning utility, fuel mix is reflected in Sub-factor 3b, “Generation and Fuel Diversity.” The risks under the carbonreduction pathway are incorporated into Factor 1 “Regulatory Framework” for regulated utilities and under Sub-factor 1a, “Stability andpredictability of regulatory regime,” for networks.



Customer preference and disruptive technologies provide both risks and opportunities

Key factors in assessing the potential impact of demand substitution and changes in customer preferences as well as risk ofdisruptive technology

» End-users request more “green energy” supply which will drive utility resource decisions. Customers may opt to entirely exit the systemto procure their own green energy.

» Besides the risk of stranded assets, the growth of such technologies could bring new players into the utility value chain and significantchanges to the utility business model.

» Rate designs with a high volumetric component may diminish utilities' ability to recover fixed costs as power demand drops amidcustomer-driven efficiency initiatives and distributed generation.

» Disruptive technology risk over the long-term could arise if a combination of self-generation and storage becomes competitive withutility rates, potentially undermining the monopoly, cost-plus business model.

In the utility sector, the evolution of disruptive technologies and changing customer preferences are closely intertwined, with theformer usually enabling the latter. Low-cost renewables, technologies supporting energy efficiency, distributed generation suchas rooftop solar, energy storage and the smart grid will all likely transform the electric system over time. These technologies areempowering customers, especially large corporates with a growing emphasis on sustainability in their boardrooms, to have a greatersay in how their power demands are met. Utility regulators are increasingly supporting these trends which promise a cleaner grid whilealso controlling costs. The technologies present utilities with both risks and opportunities, including investments in transmission andrenewables.

The greatest risk for utilities would arise in a scenario where a combination of distributed generation and energy storage eventuallybecomes competitive with utility costs and has the potential to fundamentally disrupt the monopoly, cost-plus utility business model.While we don’t see this as a short or medium term risk, utilities are prolific issuers of long-term bonds with tenors of 30-years orlonger.

» Energy efficiency has long been important to utility regulators. But its importance has increased substantially in a carbon-constrained world, including to customers. Passive homes that consume no net energy and energy-efficient office buildingsare growing rapidly in number. Energy efficiency, along with the macroeconomic transition to less energy-intensive sectors, iscontributing to a weakening of the correlation between GDP growth and power demand in developed countries, resulting in flatdemand. Where utilities have rates based on volumes, this could translate directly into lower revenues and hence delay recoveryof fixed costs until tariffs are adjusted. Even in regulatory regimes that remove direct volume risk, the risk of stranded assets mayincrease if volumes decline persistently.



Exhibit 5

When power demand is less correlated to GDP growth, volumetric rate design can be a credit negativeRate design is more important in developed countries

China - Gencos

China - T&Ds

MexicoSouth Africa

Hong Kong

Japan

South Korea

US - Vertically Integrated

US - T&Ds

EMEA - T&Ds

Bulgaria

LatAm - Transmission

LatAm - Distribution

Singapore

Philippines

India - GencosIndia - Transmission

Malaysia

Thailand

Indonesia

Hig

he

st

Vo

lum

etr

ic R

ate

s

Highest Correlation Between GDP Growth and Power Demand

Individual countries largely indicate vertically integrated utilities.Countries are listed alphabetically; the order does not pertain to correlation.Source: Moody's Investors Service

As seen in Exhibit 5, vertically integrated utilities in the US generally have the greatest exposure to the risk of lower sales volumes.Utilities in Hong Kong and networks in Europe are able to recover their fixed costs regardless of volumes, a credit positive. Incontrast, utility rates in most emerging markets are still volumetric. However, these economies’ high energy intensity and/or growingelectrification are resulting in growing sales volumes for now.

Energy efficiency also presents utilities with opportunities. In developed countries, some regulators provide utilities with financialincentives to implement efficiency programs that reduce load. For example, US states in the Northeast and West have high efficiencymetrics. Japan also has a heightened focus on energy efficiency following the Fukushima nuclear accident.

» Distributed generation (DG), primarily through rooftop solar, is similar to energy efficiency in its impact in that it reduces utilityvolumes. While Europe has implemented domestic rooftop solar through a fixed-price mechanism, known as the feed-in tariff,the US (and more recently Latin America) use Net Energy Metering policies, which value the surplus fed into the grid from rooftopsystems at the prevailing retail price of power. While DG supports customer choice for solar, it also transfers fixed costs of the gridto non-solar customers, a credit negative. Most US states are now reforming net metering in an attempt to balance the policy goalof supporting rooftop solar power with the financial health of the utility. The declining cost of solar is making this process easier.DG can also present utilities with opportunities, such as earning regulated returns on rooftop solar investments in the US state ofArizona.Other forms of DG such as fuel cells or heat pumps (negative for gas usage) have been around for decades but have not achievedeconomic viability. Unlike rooftop solar, fuel cells are independent of a variable natural resource and can generate power throughoutthe day or night, which makes them a better candidate to be a disruptive force that could fundamentally threaten the utilitybusiness model by allowing customers to exit the electric grid. But its viability is currently decades away, if it ever comes to be.

» Energy storage is perhaps the most disruptive of all emerging technologies. Electricity is the only commodity that currently lacks aneconomic storage option. Storage reduces the intermittent nature of renewables, and as battery prices decline this could erode thevalue of utility-owned fossil-generation assets, potentially threatening even relatively cleaner gas-fired generation in the long run.Similar to distributed generation, batteries allow third-party storage service providers to break the utilities' historical monopolisticrelationship with the customer. They also cause under-recovery of costs when commercial and industrial customers satisfy aportion of their peak demand from stored energy and reduce their fixed charges. On the positive side, batteries present utilities with



investment opportunities. More importantly, they reduce the cost of integrating variable wind and solar generation resources intothe grid. This will slow the increase in customers' energy bills and avoid political or regulatory intervention, a credit positive.6

» Electrification of transportation, and possibly of home heating, presents the biggest potential upside for electric utilities fromcarbon transition, both in sales volumes as well as investment potential. Moody's estimates that if the state of California were toachieve its goal of 1.5 million electric vehicles (as against more than 30 million registered vehicles) by 2025, this would result in acumulative increase in sales for the state's utilities of about 5%-6%.7 China and India have recently indicated a desire for all new carsto be electric by 2030, although no formal policies have been announced thus far. However, as discussed earlier, electrification ofhome heating poses a substantial risk over the long term to the gas distribution business.

» Regulators are giving serious thought to the smart grid and the utility of the future, combining all of the above technologies withsmart meters and appliances and the emerging “internet of things”. Smart grids accommodate two-way flow of electricity to andfrom the customer and allow third parties to offer services that improve efficiency and cut emissions while also reducing networkcosts. Although the impact of these technologies is currently difficult to predict, they portend a move away from the traditionalmodel of the utility. Some jurisdictions are exploring the possibility of significant changes to the utility business model, such as the“Reforming the Energy Vision (REV)” program in the US state of New York.

Utilities that remain focused on centralized energy generation are likely to face higher risks, while those that can take advantage ofnewer technologies and are in a position to sell energy and related services to captive customers are likely to benefit most. In ouropinion, the utility’s critical role as a grid operator is likely to remain intact or even enhanced despite all the changes. The key to creditquality is the pace of carbon transition and the supportiveness of regulators in ensuring full and timely recovery of operating costs, plusa return.

How demand substitution and the risk of technology shocks are captured in our rating methodology scorecard

Demand substitution and the risk of technology shocks affect the credit of regulated utilities primarily through regulatory cost recovery,which is considered in Sub-factor 1b “Consistency and Predictability of Regulation,” Factor 2a “Timeliness of Recovery of Operating andCapital Costs” and Sub-factor 2b “Sufficiency of Rates and Returns.” Demand substitution and technology shocks will also affect Sub-factor 3a“Market Position” and Sub-factor 3b “Generation and Fuel Diversity.”

For networks, demand substitution risk is considered in Sub-factor 1c “Cost and Investment Recovery” and Sub-factor 1d “Revenue Risk” whiledisruptive technology shocks are captured in Sub-factor 1b “Asset Ownership Model,” Sub-faactor 1c “Cost and Investment Recovery” andFactor 2 “Scale and Complexity of Capital Program.”



Regulatory framework is the critical driver of the credit impact of carbon transition

Key factors considered in evaluating the regulatory framework for carbon transition

» Regulatory authorities may disallow the recovery of operating costs, or stranded assets as part of the carbon transition.

» Tariff increases may not be timely or maybe inadequate if the carbon transition requires tariff increases that are politically unpalatable.

» Managing relationships with regulators and the consistent application of cost recovery mechanisms and timely tariff reviews are key.

Regulated utilities and networks are highly rated sectors at Moody's. Their median rating of Baa1 compares with Ba3 for all non-financial corporates and a 10-year cumulative default rate that is 11x lower. The regulatory framework, which allows utilities torecover all operating costs and earn a return of and on investments, is the fundamental driver of this difference in credit quality. Utilityregulators consider the impact of carbon policies, demand substitution, customer preferences and technology risks in setting utilitytariffs, which will ultimately determine the credit impact of the carbon transition on utilities. Our analysis currently incorporates a viewthat regulators will support recovery of most or all costs related to carbon transition and extreme weather. In this context, utilities areexposed to be possibility that:

» Tariff increases may not be timely or may be inadequate if rate hikes needed are large and politically unpalatable.

» Regulatory authorities may disallow the recovery of costs associated with stranded assets or caused by extreme weather.

Tariff increases may be required as utilities invest in new generation, transmission and smart distribution grids, as well as to recovercapital invested in assets whose useful life is shortened by decarbonization, such as gas T&D assets facing a switch to electric heatingor coal plants that need to shut down. The age of a utility's regulated asset base can be an indication of stranded asset risk, becauseutility rates are usually set to recover investments over the useful life of the asset. For example, in India a significant portion (65%) ofthe coal-fired fleet is less than 10 years old, while in the US a large majority of coal plants are over 30 years old. In South Korea andChina, the age of coal plants is more evenly distributed.

Regulators can mitigate this risk by shortening the assets’ depreciation life, thereby accelerating cost recovery and reducing the riskof stranded assets. This was implemented in 2013 in Britain for gas networks, and a similar trend is emerging for coal plants in the US.Regulators may also mitigate this risk by finding alternative uses for the assets (such as using gas distribution networks for alternativefuels).

Other aspects of existing regulatory frameworks also need to evolve given the material and rapid changes and technology shifts in theindustry. The introduction of a capacity fee for network connections, for example, allows for recovery of the fixed costs of maintainingthe grid or charging exit fees for departing customers. In addition, a narrow national or sub-national view may be replaced with anincreased focus on long-term planning across regulatory jurisdictions.

Affordability will remain the key focus for regulators, who are acutely conscious of the benefits of low electricity tariffs to economicgrowth. Affordability concerns could lead to deferral of cost and investment recovery, a credit negative. Renewable subsidies, especiallyin Europe, have contributed to significant increases in household energy costs, increasing the political scrutiny of all elements of bills,including network charges. Globally, concerns around affordability are being partly mitigated by the lower prices of LNG and shale gasin recent years and the sharply declining cost of renewables. In some parts of the US, utilities have been able to shut coal plants in favorof renewables while keeping rates flat or even lower.

Navigating the trade-off between decarbonization investments, the need to keep tariffs low, and maintaining financial strength will bea key focus of utility managements. Ultimately, timely cost recovery and consistent application of regulatory frameworks will be keyto maintaining credit quality. Appendices A and B summarize cost recovery mechanisms in countries where we rate regulated utilities.Stranded cost recovery remains undefined or untested in many countries. This risk is highest in countries transitioning from regulated



to unregulated markets, such as Japan and Mexico. However, this risk is also mitigated for those utilities that are government-relatedissuers (GRIs) and benefit from government support.

How the regulatory framework is captured in our rating methodology scorecard

For regulated utilities, the regulatory framework is assessed in Sub-factor 1b “Consistency and Predictability of Regulation”, Sub-factor 2a“Timeliness of Recovery of Operating and Capital Costs” and Sub-factor 2b “Sufficiency of Rates and Returns.” An inability to recover costsfully will also reflect in a weaker financial profile, which is considered in Factor 4 “Financial Strength.”

For networks, the regulatory framework is reflected in Sub-factor 1a ”Stability and Predictability of Regulatory Regime”, “Sub-Factor 1c “Costand Investment Recovery.” An inability to recover costs fully will also be reflected in a weaker financial profile, which is considered in Factor 4“Leverage and Coverage.”



Appendix A: Illustrative summary of cost-recovery mechanisms across select jurisdictions available forvertically integrated utilities

Regions Selected JurisdictionsType of regulated utility &

ownershipType of regulation Comment

CanadaVI,

IOU and GRICost of Service

• IOUs generally have strong cost recovery mechanisms in place that enable them to earn their allowed return on equity. Generally IOUs have either no or low levels of vertical integration.

• GRIs which typically undertake the vast majority of generation, and in some provinces all of the T&D, often have

significant challenges related to timely cost recovery. However they may also benefit from material support from their

government owners which may include a government debt guarantee.

AmericasUSA (States with

regulated generation)

VI,

IOUCost of Service

• Broad group of cost and investment recovery mechanisms through annual rate base proceedings.

• Increasing use of special purpose automatic recovery riders or trackers and fixed charges but generation revenues remain largely volumetric.

• Increasing application of securitization financings to recover storm hardening investments and early retirement of assets.

• Regulators have been overall pro-active in mitigating the cost-shift challenges related to distribution generation and

net metering policies.

Costa Rica, UruguayVI,

GRICost of Service

• The two GRI vertically integrated utilities in these countries face limited risk as transition to decarbonization grid has already taken place (power nearly 100% sourced from renewable sources).

MexicoVI,

GRIOther

• Historically, the government has set Comisión Federal de Electricidad's (CFE) revenue tariffs via the regulator.

• Uncertainty regarding the medium-term effect of the Energy Reform on CFE; however, we assume strong implied

government support.

• The modest size of CFE’s coal-fired fleet limits its medium-term exposure to stranded assets.

ChinaGencos,

Mainly GRIOther

• Sector reforms limit clarity on the recovery of stranded assets.

• However, Moody’s assumes high likelihood of partial recovery but pending outcome of discussions between gencos,

regulators and the local government’s fiscal authorities (varies across provinces).

• Examples of economic compensations provided after a genco’s coal-fired plant retirement in 2015 included:

authority for the genco’s new generation assets to take over the heating business provided by the retired plant and government’s instructed requirement for the local distribution company to increase its power procurement from the genco’s new assets.

Hong KongVI,

Privately owned

Scheme of Control

(SOC) agreement with

the government

• Protection for stranded costs provided under current agreement signed with the government. The clause stipulated

that the government should discuss and finalize the stranded costs and the relevant recovery in no less than 36

months prior to the proposed market change.

IndiaVI and Gencos,

Privately owned and GRICost of Service

• Regulated returns delinked from volumes.

• Established regulations to determine rate base and cost recovery but specific regulation about cost recovery of retired power plants pending.

• However, rates for the recovery of coal-fired assets are premised on a relatively short useful life (25 years).

Asia IndonesiaVI,

GRICost of Service

• Regulations are based on recovery of costs but there is no determination of the rate base; no incentive or penalties

for performance.

• The country is likely to come up with new set of regulations over next few years (to set targets for operating norms

and establishing rate base).

Japan

VI,

Mainly privately owned and

one GRI

Cost of Service

• Nationwide regulation but market is in transition to deregulation.

• Tariff that allows for total cost recovery will remain in place for several years.

• Utilities are also allowed to offer non-regulated pricing plans (that are lower than the regulated tariffs) to compete

against new entrants that may offer cheaper pricing plans. The utilities are offering such prices to selective / targeted

customers or are providing bundled electricity and gas packages.

• After the market transitions to full deregulation, uncertainty remains surrounding recovery of stranded costs.

MalaysiaVI,

GRICost of Service

• Defined regulation for determining rate base and cost recovery.

• However, short history of the regulatory regime (cost recovery of retired power plant costs pending).

South KoreaVI,

GRICost of Service

• Regulator may consider the recovery of stranded costs and environmental compliance costs for state-owned Korea

Electric Power Corporation (KEPCO).

• However, weak consistency in setting tariffs, particularly in periods of high inflation, creates some uncertainty.

BulgariaVI,

GRICost of Service

• Regulated tariffs for the conventional power generation and transmission operations of Bulgarian Energy Holding (BEH), the GRI vertically integrated regulated utility, include variable plus fixed cost recovery components; however,

rates of return are often very low (WACC: 1.1% for transmission) and do not allow for a profit margin.

• Recovery of stranded costs is uncertain and risk of inflection point is high due to accumulated system deficits and high affordability concerns (in some cases electric and heating bills represent around 20% of disposable income).

EMEAGulf Cooperation

Council (Middle East)

VI (Dubai, Saudi Arabia),

Gencos (Oman, Qatar),

All GRI

Other

• In most Middle East countries, revenue tariffs are set by the government and are not always cost reflective.

• Significant entrenchment between the GRI utilities, regulators and government along with strategic importance that

enhances the likelihood of stranded cost recovery.

IsraelVI,

GRICost of Service • Fuel pass-through.

South AfricaVI,

GRICost of Service

• In practice, fully cost-reflective tariffs have yet to be implemented.

• However, several instances of tangible support underpin our expectation of high government financial support to

Eskom.




Appendix B: Illustrative Summary of cost-recovery mechanisms across selected jurisdictions availableto pure transmission and network utilities



Canada (T&Ds in

Provinces with

unregulated

generation)

T&D,

Privately ownedCost of Service

• In the province of Alberta, the investor owned utilities operate in a credit supportive regulatory environment that generally enables

utilities to recover their costs and earn their allowed returns.

USA (States with

unregulated

generation)

T&D,

IOUCost of Service

• Broad group of cost and investment recovery mechanisms through annual rate base proceedings.

• Increasing use of special purpose automatic recovery riders or trackers and revenue decoupling mechanisms, which delinks volumes

from revenue for distribution comapanies.

• Increasing application of securitization financings to recover storm hardening investments.

• Stranded cost risk exposure for regulated electric T&Ds is less of a risk over the medium-term due to material investments still

required to improve T&D services and reduce electricity losses.

• Power demand still highly correlated with GDP-growth.

• Overall, 4-5 price controls; distribution tariffs are subject to price cap (volumetric) but transmission rates are based on revenue cap

(non-volumetric).

• Rates are set to recover pre-approved investments and to reflect efficiencies from a previous tariff period.

• Net metering billing policies are under development. Actual penetration of grid-connected, small-scale, self-generation is still modest.

• Overall new transmission assets have been allocated under public auctions for the last decade . Rates (winning bid) theoretically

allow cost recovery of operations and capital during the multi-year operational periods.

ArgentinaT&D,

IOUCost of Service;

• Although improving, Argentina has a long track-record of high political intervention in the tariff review process.

• In early 2017, new administration set revised tariff for both T&D. Tariff regime established a new tariff formula that incorporates

inflation adjustment .

• Tariff formula based on New Replacement Value (VNR).

• Expected rapid incorporation of renewables will challenge transmission going forward and auctions to increase transmission capacity are expected for next year.

BoliviaT&D,

GRICost of Service

• T&D subject to regulated tariffs.

• Tariff review every 4 years inconsistently applied. Out of 6 reviews, only one resulted in a tariff increase.

• T&D assets majority owned by government entities due to an extensive nationalization of energy and strategic assets in Bolivia

(Energy, Oil & Gas, etc.).

• Bolivia's ample gas resources has prevented development of renewables.

BrazilT&D,

IOUs and some GRICost of Service

• Since 2006, transmission assets have been subject to 30-year concession periods (public auctions); After expiration, assets are

subject to new auctions with updated rates reflecting only O&M costs (no volume exposure); Early renewable process of concessions

in 2012 raised questions about the predictibiltiy of the regulatory environment but the distribution tariff reviews have been supportive

and transparent.

• 4-5 price control periods for T&D assets; Rate base calculated based on optimized depreciation.

• Distribution assets are also subject to 30-year concession periods (starting to expire in the late 2020s) but are subject to renewal for

an additional 20 years after expiration; Very high energy losses (in some cases > 20%) require significnat investments.

• Relatively short tenor of the local capital markets debt (max five to seven years or up to 12 years for special projects funded by the

Brazilian Development Bank) allows utilities to better manage their long-term capital structure if stranded asset risk increases over the

long-term.

ChileT&D,

IOUCost of Service

• History of transparent regulatory framework; One of the first contries to implement deregulation (1980s).

• Distribution assets are subject to indefinite concessions; Since 2006, transmission assets are allocated under public auctions over

25-year operational periods. After expiration, these T assets will be also subject to tariff reviews.

• 4-year price controls for distribution (revenue cap) and transmission (pre-2006; price cap) tariffs; Rate base reflects Value of new

Replacement (VNR).

• Chilean T&Ds will be among the first in the region to face the challenges and opportunities as in other developed markets, due to

Chile's material development of solar and wind projects (not regulated) and the efficiencies in power demand growth.

ColombiaT&D,


• Since 2000, revenues of transmission assets reflect the terms of winning public auctions (25 years); But after expiration, assets will

be subject to the 5-year tariff reviews applicable to pre-2000 transmission assets (revenue cap, non-volumetric).

• Distribution assets are subject to indefinite Operational Zone Authorizations; Regulators are in the process of switching the rate base

calculation for transmission (pre-2000) and distribution from VNR to optimized depreciation model; Distribution tariffs will also possibly

become subject to revenue caps (non-volumetric) from the current price cap.

• Track-record of supportive tariff reviews outcomes, but they typically take place later than the estipulated five year period (allows the

utiltiy to benefit longer from gained efficiencies).

• The country's material hydro-generation has deterred significant developments in other renewables; however, new legislation is

expected to initiate investments in wind and solar.

PeruT&D,


• Long-track record of public auctions to allocate transmission assets (started in 1998) under 30-year concesion periods; after

expiration, assets cold revert to the State, with rates set only to recover O&M costs (no volume exposure).

• Distribution assets are subject to indefinite concessions; Distribution tarrifs have a 4-year price controls (price cap, exposed to

volumes) and rate base premised on VNR.

• Track-record of overall supportive and transparent tariff reviews.

ChinaT&D,

GRIOther

• Sector reforms limit the clarity on the recovery of stranded assets.

• However, Moody’s assumes high likelihood of partial recovery but pending outcome of discussions between gencos , regulators and

the local government’s fiscal authorities (varies across provinces).

Hong KongT&D,

Privately owned

Scheme of Control (SOC)

agreement with the government

• Protection for stranded costs provided under current agreement signed with the government. The clause stipulated that the

government should discuss and finalize the stranded costs and the relevant recovery in not less than 36 months prior to the proposed

market change.

IndiaT&D,


• Regulated returns delinked from volumes.

• Established regulations to determine rate base and cost recovery.

Philippines T&D Cost of Service• We do not rate the T&D but Transmission operates under a concession agreement with cost plus reasonable return and

performance incentives.

Singapore T&D,

GRICost of Service

• 5-year reset periods.

• No volume exposure beyond +/-2% of forecast volume.

• Return on regulated asset base.

• Performance incentives.

South KoreaT&D,


• Issuers pass cost movements onto end-users without exposure to volume risk.

• However, companies show a weak track record of a consistent cost-pass through tariff mechanism, posing a risk to timely cost pass-

through.

South America: Regulatory features common across regulatory jurisdictions

in region

Americas

Asia





Belgium

T&D,

Non-GRI Government

ownership

Mix of cost-plus and incentives• 4-5-year price controls, mix of cost-plus and return on regulatory assets, revenue cap (no volume exposure), total expenditure

assumptions included in revenue allowance, international (transmission) and regional (distribution) efficiency benchmarking.

Czech Republic

T&D,

Privately owned and

GRI

Incentive-based• 5-year price controls, revenue cap (no volume exposure), return on regulated asset base, opex expenditure allowance based on

historic costs with company-specific and sector-wide efficiency targets, performance incentives on opex.

Finland

T&D,

Mostly GRI and some

privately owned

Rate of return with incentives• 4-year regulatory periods, revenue cap (no volume exposure), return applied on regulated asset base (regulatory capital), opex

allowance, factoring in company-specific and sector-wide efficiency targets, performance incentives.

FranceT&D,

Privately ownedCost of service

• 4 year price controls, return on regulatory asset base with modest performance incentives, no volume risk.

• Indirect government interests.

GermanyT&D,

Privately ownedIncentive-based

• 5-year price controls, revenue cap (no volume exposure), return on regulatory equity, total expenditure allowance, factoring in

company-specific and sector-wide efficiency targets.

Great BritainT&D,

Privately ownedIncentive-based

• 8-year price controls, revenue cap (no volume exposure), return on regulated asset base, total expenditure allowance, factoring in

company-specific and sector-wide efficiency targets, performance incentives.

ItalyT&D,

Majority privately owned

Cost of service, moving toward

incentive-based

• 4-8-year price controls, price cap, limited volume risk, return on regulatory asset base, total expenditure allowance, sector-wide and

company-specific efficiency targets, performance incentives.

• Some minority government investment.

NetherlandsT&D,

GRIIncentive-based

• 5-year price controls, mix of revenue (transmission) and price (distribution) cap, limited volume risk, return on regulatory asset base,

total expenditure assumptions included in revenue allowance, sector-wide and company-specific efficiency targets (transmission) or

performance incentives compared with sector average (distribution).

Norway

T&D,

Mostly GRI and some

privately owned

Incentive-based• No predefined price control period but key principles last for a minimum of 5 years, e.g. return on regulated asset base, revenue cap

(no volume exposure), cost allowances factor in both historical and forecast (normalised) costs.

PolandT&D,


• 5-year regulatory period with return on regulated asset base and tariffs reset annually (electricity distribution), operating costs subject

to efficiency targets.

Republic of IrelandT&Ds,

GRICost of service

• 5-year price controls, revenue cap (no volume exposure), return on regulatory asset base, total expenditure allowance, sector-wide

and company-specific efficiency targets, performance incentives.

SpainT&Ds,


• 4-6-year price controls, return on regulatory asset base with performance incentives (electricity), iterative formula and variable

element for gas (limited volume risk).

Sweden

T&D,

Mostly GRI and some

privately owned

Incentive-based• 4-year price controls, revenue cap (no volume exposure), return on regulated asset base (regulatory capital), opex allowances factor

in historical costs with company-specific and sector-wide efficiency targets, performance incentives.

Australia

T&D,

Privately owned and

GRI

Incentive-based• 5-year price controls, return on regulated asset base, total expenditure allowance, performance incentives.

• Revenue cap (no volume exposure) for electricity T&D and tariff cap for gas T&D (with modest volume risk).

New Zealand

T&D,

Privately owned and

GRI

Incentive-based

• 5-year price controls, return on regulated asset base, total expenditure allowance, performance incentives.

• Revenue cap (no volume exposure) for electricity Transmission, with Distribution expected to move to revenue cap at the next reset.

• Tariff cap for gas T&D (with modest volume risk).

Oceania

EMEA




Appendix C: Rating Methodology Grids

Exhibit 9

Regulated Electric and Gas Utilities

Broad Rating Factor Factor Weighting Rating Sub-factor

12.5% Legislative and Judicial Underpinnings of the Regulatory Framework

12.5% Consistency and Predictability of Regulation

12.5% Timeliness of Recovery of Operating and Capital Costs

12.5% Sufficiency of Rates and Returns

5% Market Position

5% Generation and Fuel Diversity

7.5% (CFO Pre-W/C + Interest) / Interest (3 Year Avg)

15% (CFO Pre-W/C) / Debt (3 Year Avg)

10% (CFO Pre - W/C - Dividends) / Debt (3 Year Avg)

7.50% Debt / Capitalization (3 Year Avg)

REGULATORY FRAMEWORK

ABILITY TO RECOVER COSTS

AND EARN RETURNS

DIVERSIFICATION

FINANCIAL STRENGTH


Exhibit 10

Regulated NetworksBroad Rating Factor Factor Weighting Rating Sub-factor

15% Stability and Predictability of Regulatory Regime

5% Asset Ownership Model

15% Cost and Investment Recovery (Ability and Timeliness)

5% Revenue Risk

SCALE AND COMPLEXITY OF

CAPITAL PROGRAM10% Scale and Complexity of Capital Program

FINANCIAL POLICY 10% Financial Policy

10% Adjusted Interest Coverage Ratio or FF Interest Coverage (3 Year Avg)

12.5% Net Debt / RAB (3 Year Avg) OR Net Debt / Fixed Assets (3 Year Avg)

12.5% FFO / Net Debt (3 Year Avg)

5% RCF / Net Debt (3 Year Avg)

LEVERAGE AND COVERAGE

REGULATORY ENVIRONMENT

AND ASSET OWNERSHIP

MODEL




Moody's Related ResearchEnvironmental Research

» Cross Sector – Global: Moody’s Approach to Assessing the Credit Impacts of Environmental Risks, 30 November 2015

» Environmental Risks: Heat Map Shows Wide Variations in Credit Impact Across Sectors, 30 November 2015

» Environmental Risks and Developments: Paris Agreement Advances Adoption of Carbon Regulations; Credit Impact to Rise, 22 April2016

» Environmental Risks and Developments: FSB Task Force Could Begin to Clear Fog on Climate Risk Disclosures, 14 April 2016

» Environmental Risks and Developments-Global: Paris Agreement Advances Adoption of Carbon Regulations; Credit Impact to Rise,22 April 2016

» Environmental Risks: Moody’s To Analyse Carbon Transition Risk Based on Emissions Reduction Scenario Consistent with Paris, 28June 2016

» Environmental Risks: Risks and Opportunities: What the Paris Agreement Means for Capital Markets, 20 July 2016

» Environmental Risks: Automotive Sector Faces Rising Credit Risks from Carbon Transition, 20 September 2016

» Global Unregulated Utilities and Power Companies: Carbon Transition Brings Risks and Opportunities, 19 October 2016

» Environmental Risks: Oil and Gas Industry Faces Significant Credit Risks from Carbon Transition, 26 April 2017

» Environmental Risks: Shift in US Climate Policy Would Not Stall Global Efforts to Reduce Carbon Emissions, 16 February 2017

» Environmental Risks: Paris Agreement to Take Effect, Adoption of Carbon Reduction Policies to Accelerate, 5 October 2016

Utilities Sector Research

» Renewable Energy - Global: Falling cost of renewables reduces Paris Agreement compliance risks, 6 September 2017

» Renewable Energy - Global: Renewables sector risks shift as competition reduces reliance on government subsidy, 6 September 2017

» Renewable Energy - Latin America: Compelling Fundamentals and Carbon Reduction Targets Drive Growth, 6 September 2017

» Renewable Energy - China: Favorable policy environment drives growth in China's renewable energy sector, 6 September 2017

» Renewable Energy - India: Strong growth prospects, but challenges from offtakers, evolving policy framework, 26 June 2017

» Power Sector - China: Challenging environment continues, more opportunities in renewable energy, 2 August 2017

» GB Regulated Energy Networks: Energy storage to enable a more sustainable electricity transmission grid, 6 September 2017

» Unregulated Power and Utilities - US: Marcellus Shale Gas Buildout Wreaks Havoc on PJM Power Market, 8 May 2017

» Project Finance – EMEA: Saudi Arabia’s Renewable Energy Plans: Strong Rationale, Untested Framework, 5 April 2017

» US - Utilities and Public Power: US Executive Order on Clean Power Plan Will Slow, But Not Halt, Transition Away From Coal, 31March 2017

» US Power and Utilities: Rate-Basing Wind Generation Adds Momentum to Renewables, 15 March 2017

» US Power & Utilities: Economics, End-User Sustainability Policies Drive Renewables in a post-CPP World, 10 March 2017

» EMEA Project Finance: South African renewables are less dependent on subsidy, a positive for project finance issuers, 16 September2016


https://www.moodys.com/research/Cross-Sector-Global-Moodys-Approach-to-Assessing-the-Credit-Impacts--PBM_1010009

https://www.moodys.com/research/Environmental-Risks-Heat-Map-Shows-Wide-Variations-in-Credit-Impact--PBC_1009845

https://www.moodys.com/researchdocumentcontentpage.aspx?docid=PBC_1024553





























» Power Sector - India : Growth in Renewable Energy Capacity Will Challenge Fossil Fuel Operators, 4 April 2016

» US Regulated and Unregulated Utilities: Batteries Charge Up For the Electric Grid, 24 September 2015

» Project Finance: European renewable energy assets poised for refinancing, 23 September 2015

Endnotes1 See our highlight box titled “Regulated utilities, regulated networks and unregulated utilities”

2 United Nations Framework Convention on Climate Change http://newsroom.unfccc.int/unfccc-newsroom/indc-synthesis-report-press-release/

3 See “Moody’s To Analyse Carbon Transition Risk Based On Emissions Reduction Scenario Consistent with Paris Agreement,” published 28 June 2016

4 Stranded assets are assets that are no longer economically viable and where the regulator disallows recovery from end-users.

5 See “Falling cost of renewables reduces risks to Paris Agreement compliance,” published 6 September 2017.

6 See “Energy storage to enable a more sustainable electricity transmission grid,” published 6 September 2017.

7 See “Electric car growth boosts utilities; mixed implications for autos and state finances,” published 31 October 2016.










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