Opinion

Green America: Renewable Standards, Tax Credits, And What's Next


In the first part of this series, S&P Global Ratings discussed the development of the green bond market in the U.S., some of the hurdles, how it differs from the European and Asian markets, and the opportunities that await investors as the American grid continues to transform. But underpinning the whole discussion is the torrent of renewable energy that continues to enter the U.S. market. Here, we'll take the conversation beyond labelled green bonds to discuss several other factors influencing the growth of renewable energy in the U.S., including renewable portfolio standards, which mandate that power generators use renewable energy sources; production tax credits, which can help finance renewable projects; and feed-in tariffs, which can potentially heighten the demand for renewable energy.

Overview

Renewable portfolio standards (RPS) are legally binding policies that require retailers of eletric utilities to deliver a specified amount of electricity from renewable sources. Iowa established the first RPS in 1983, followed by Nevada and Massachussets in 1997. Today, 29 states, three territories, and the District of Columbia have instituted RPS. In addition, eight states and one territory have instituted renewable energy goals, which provide nonlegally binding targets for renewable electricity generation.(1) Absent a Clean Power Plan or similar carbon mandate, it's not clear that this tally will be pressured to grow in the near term. But even as the Clean Power Plan has come under siege during the Trump Administration, states having renewable standards have expanded them, sometimes with more ambitious goals and more specific carve-outs for new asset classes.

The design of RPS differs by state. Most standards incorporate one or more of the following aspects:

Overall goal

Most often, states set a percentage of kilowatt hours of electric sales that must be generated from renewable sources. Some states diverge from this model, mandating instead that renewable energy sources satisfy a portion of energy capacity or peak demand, for example.(2)

Carve-outs

To encourage the development of specific renewable energy sources, a state may specify carve-outs within the overall renewable target. Carve-outs require a portion of the renewable electricity to be generated by a specific source or method, such as solar, hydro, wind, distributed generation, or energy transformation. States also designate carve-outs for certain classes or tiers of renewable energy sources. The definition of each class or tier varies by state.(3) This could become increasingly valuable as emerging technologies such as offshore wind or battery storage develop, but these newer carve-outs could need technology specific renewable goals to advance. Indeed, there may be political motivations for such specific mandates--both Maryland and Massachussetts, for instance, have created tailored approaches to offshore wind, hoping to stimulate the industry within their borders, which is still nascent in the U.S.

Applicable sectors

RPS specify whether goals and carve-outs apply to all players in renewable electricity generation or to specific players. Applicable sectors include investor-owned utilities (IOUs), retail suppliers, municipal utilities, cooperative utilities, and local governments. The highest requirements are typically applied to IOUs(4), but, increasingly, muncipalities in select parts of the country are creating their own goals to decarbonize, without necessarily being mandated to do so by states.

Credit multipliers

Electric utility retailers in certain states can offset shortfalls in their own renewable energy generation by purchasing tradeable credits. The credits indicate that another retailer has generated an amount of renewable electricity equal to the shortfall. States may promote specific renewable sources through the use of credit multipliers, which permit one unit of renewable electricity to count for more than one credit.(5)

Cost caps

To temper the impact of RPS on electricity customers, 20 states and the District of Columbia have set caps on the increase in electricity prices charged by providers (see tables 1-7).(6)

U.S. States And Territories: Established Renewable Portfolio Standards Or Goals

Table 1  |  Download Table

Northeast
No.StateRPS or Goal?Date establishedOverall requirement/targetCost capCarve-outsCredit multipliersMisc.
1MERPS199940% of electricity sales by 20176.10%Class I (new) sources: 10% by 2017. Wind: 2,000 MW of installed capacity by 2015; 3,000 MW of installed capacity by 2020, including offshore or coastal; and 8,000 MW of installed capacity by 2030, including 5,000 MW from offshore and coastal.Community-based renewable energy 
2VTRPS2005 (voluntary target); 2015 (standard)55% of electricity sales by 2017; 75% by 2032-Distributed Generation: 10% by 2032. Energy Transformation: 12% by 2032 (includes weatherization, thermal energy efficiency, and heat pumps).  
3NHRPS200724.8% of electricity sales by 20257.30%Class I (new) sources: 15% by 2025Solar: 0.3% by 2014  
4CTRPS199827% of electricity sales by 20207.10%Class I new renewable energy sources (including distributed generation): 20% by 2020. Class I or II (biomass, waste-to-energy and certain hydropower projects): 3% by 2010. Class III (combined heat and power, waste heat recovery and conservation): 4% by 2010.  
5MARPS1997Class I: 15% of electricity sales by 2020 and an additional 1% each year after. Class II: 5.5% of electricity sales by 20158.00%Photovoltaic: 400 MW required. Class II (resources in operation by 1997): 3.6% renewable energy and 3.5% waste-to-energy.  
6RIRPS200414.5% of electricity sales by 2019, with increases of 1.5% each year until 38.5% by 20359.50%  The state has a separate long-term contracting standard for renewable energy, which requires electric distribution companies to establish long-term contracts with new renewable energy facilities.
7NYRPS200429% of electricity sales by 2015; 50% by 2030 (REV- currently in process)1.70%Distributed Generation: 8.4% of annual incremental requirement.  

Table 2  |  Download Table

Mid-Atlantic
No.StateRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit Multipliers Misc.
8PARPS200418% of electricity sales by 2020-2021-Tier I (includes photovoltaic): 8% by 2020-2021. Tier II (includes waste coal, distributed generation, large-scale hydropower and municipal solid waste): 10% by 2020-2021. Photovoltaics: 0.5% by 2020-2021  
9NJRPS199924.5% of electricity sales by 202012.60%Class I or Class II (resource recovery or hydropower): 20.38% by 2020-2021. Solar-electric: 4.1% by 2027-2028. Offshore wind: 1,100 MW.  
10DERPS200525% of electricity sales by 2025-20263.00%; 1.00% (PV)Photovoltaics: 3.5% of requirement by 2025-2026.Varies by technology 
11DCRPS200520% of electricity sales by 2020; 50% by 20327.60%Solar: 2.5% by 2023.  
12MDRPS200425% of electricity sales by 20206.50%Solar: 2.5% by 2020. Offshore wind: 2.5% maximum by 2017.  

Table 3  |  Download Table

Southeast
No.StateRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit Multipliers Misc.
13VAGoal200712% of electricity sales by 2022 (IOUs); 15% by 2025 (IOUs)- Varies by technology 
14NCRPS200712.5% of electricity sales by 2021 (IOUs); 10% by 2018 (munis and co-ops)1.40%Solar: 0.2% by 2018. Swine Waste: 0.2% by 2018; and Poultry Waste: 900,000 MWh by 2015Biomass facilities located in cleanfields renewable energy demonstration parks 
15SCGoal20142% of aggregate generation capacity by 2021-Systems less than 1 MW: 1% of aggregate generation capacity, including at least 0.25% of total generation from systems less than 20kW. 1–10 MW facilities: 1% of aggregate generation capacity.  

Table 4  |  Download Table

Midwest
No.StateRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit Multipliers Misc.
16OHRPS200825% of electricity sales by 20261.80%12.5% Renewable Energy Resources. 12.5% Advanced Energy Resources (advanced energy resources includes co-generation, advanced nuclear power and clean coal). Solar: 0.5%.  
17INGoal201110% of electricity sales by 2025-  30% of the goal may be met with clean coal technology, nuclear energy, combined heat and power systems, natural gas that displaces electricity from coal and other alternative fuels.
18ILRPS200725% of electricity sales by 2025-20261.30%Distributed Generation: 1% of annual requirement beginning in 2015 for IOUs. Wind: 75% of annual requirement for IOUs, 60% of annual requirement for alternative retail electric suppliers. Photovoltaics: 6% of annual requirement beginning in 2015-2016.  
19IARPS1983105 MW of generating capacity for IOUs-   
20MIRPS2008; 201615% of electricity sales by 2021 (standard). 35% by 2025 (goal, including energy efficiency and demand reduction)3.10% Varies by technology 
21WIRPS199810% of electricity sales by 2015-  Standard varies by utility: 2011-2014: utilities may not decrease its renewable energy percentage below 2010 percentages.; 2015: utilities must increase renewable energy percentages by at least 6% above their 2001-2003 average.; Utilities may not decrease their renewable energy percentage after 2015.
22MNRPS200726.5% of electricity sales by 2025 (IOUs). 25% by 2025 (other utilities)-Solar: 1.5% by 2020 (other IOUs); Statewide goal of 10% by 2030. Xcel Energy has a separate requirement of 31.5% by 2020.
23NDGoal200710% of electricity sales by 2015-   
24SDGoal200810% of electricity sales by 2015-   
25MORPS200715% of electricity sales by 2021 (IOUs)1.00%Solar-electric: 2%  
26KSGoal201515% of electricity sales by 2015-2019. 20% of peak demand capacity by 2020Caps gross RPS procurement costs.   

Table 5  |  Download Table

Southwest
No.StateRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit Multipliers Misc.
27OKGoal201015% of electricity sales by 2015-   
28TXRPS19995,880 MW by 2015; 10,000 MW by 2025 (goal; achieved)3.10%Non-wind: 500 MW (goal).  

Table 6  |  Download Table

West
#StateRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit Multipliers Misc.
29HIRPS200130% of electricity sales by 2020; 40% by 2030; 70% by 2040; 100% by 2045-   
30CARPS200233% of electricity sales by 2020; 40% by 2024; 45% by 2027; 50% by 2030Determined by the California Public Utilities Commission  2013 amendment allows the California Public Utilities Commission to adopt additional requirements.
31ORRPS2007Utilities with 3% or more of the state's load: 25% of electricity sales by 2025; 50% by 2040. Utilities with 1.5% - 3% of the state's load:10% by 2025. Utilities with less than 1.5% of the state's load: 5% by 20254.00%Photovoltaics: 20 MW by 2020 (IOUs).Photovoltaics installed before 2016.The state's two investor-owned utilities must phase out coal generation by 2035.
32WARPS20069% of electricity sales by 2016; 15% by 20204.00% Distributed generationStandard is applicable to all utilities that serve more than 25,000 customers. Requirement also includes all cost-effective conservation.
33MTRPS200515% of electricity sales by 20150.10%   
34NVRPS199725% of electricity sales by 2025-Solar: 5% of annual requirement through 2015, 6% for 2016-2025.Photovoltaics and peak energy savings. 
35UTGoal200820% of electricity sales by 2025-   
36AZRPS200615% of electricity sales by 2025-Distributed Generation: 30% of annual requirement in 2012 and thereafter.Varies by technology 
37NMRPS200220% of electricity sales by 2020 (IOUs). 10% by 2020 (co-ops)3.50%Solar: 20% by 2020 (IOUs); Wind: 30% by 2020 (IOUs); Other renewables, including geothermal, biomass and certain hydro facilities: 5% by 2020 (IOUs). Distributed Generation: 3% by 2020 (IOUs).Solar energy that was operational before 2012. 
38CORPS200430% of electricity sales by 2020 (IOUs). 10% or 20% for municipalities and electric cooperatives, depending on size.2.00%Distributed Generation: 3% of IOU retail sales by 2020; 1% of cooperative retail sales by 2020 (for those providing service to 10,000 or more meters); and 0.75% of cooperative retail sales by 2020 (for those providing service to less than 10,000 meters).Varies by technology 

Table 7  |  Download Table

Territories
No.TerritoryRPS or Goal?Date EstablishedOverall Requirement/TargetCost CapCarve-outsCredit MultipliersMisc.
39NMIRPS2007; goal reduced in 201420% of net electricity sales by 2016-  Requirement allows for non-compliance if it is not cost-effective.
40PRRPS201020% of electricity sales by 2035-  Requirement does not take effect until 2015.
41UVIRPS200920% of peak demand capacity by 2015; 25% by 2020 30% by 2025; up to 51% after 2025-  Standard will increase until a majority of capacity is from renewable or alternative energy.
42GUGoal200825% of net electricity sales by 2035-   
Source: Table created by S&P Global Ratings based on data from DSIRE.

According to the Lawrence Berkeley National Laboratory, RPS-driven capacity additions comprise 56% of the 120 GW of renewable energy capacity built in the U.S. since 2000. Notably, over 10% of RPS capacity additions are built in states without RPS in place; that is, in order to satisfy RPS-driven demand in neighboring states with lofty standards. Historically, wind has comprised the majority of RPS-related capacity additions.(7) In our opinion, significant regulatory support for wind has contributed to the weakening credit quality of independent power producers (IPPs), which often include large quantities of conventional baseload generation.

In recent years, wind capacity has continued to grow in the U.S., surpassing previous expectations. However, among RPS-related capacity additions, solar has recently eclipsed wind, a trend that should continue in the future. The change is due to two factors: 1) increasing solar carve-outs and 2) declining costs of utility-scale solar relative to utility-scale wind. The Berkeley Lab estimates that in 2016, 79% of RPS-driven capacity additions were solar(8), and this growth hasn't just been in high resource areas.

Regionally, RPS have driven strong growth in renewable energy capacity in the Northeast, Mid-Atlantic, and West. Conversely, the majority of renewable capacity growth in Texas, the Midwest, and the Southeast is not the result of RPS policies(9), but driven more by market factors and investment tax credits, as well as, in some instances, more robust resources.

Satisfying currently existing RPS targets will require U.S. renewable energy capacity to increase by 40%, or 55 GW, by 2030. This means that renewable capacity will need to increase by an average of 4 GW annually. While this seems like a tall order, historically, RPS-related renewable capacity has increased by 6 GW each year in the U.S.(10)

In the U.S., the renewable portfolio standards have been exclusively issued at the state level even as certain controversial federal policies--namely the investment and production tax credits--have supported increasing renewable capacity. Absent any federal policy on carbon emissions for electricity generation, it remains unlikely a national renewable portfolio standard, such as those seen in some European economies, would be imposed. Even the legality of the Clean Power Plan, which did not go so far as imposing a renewable standard, was in question before its recent repeal.

Tax Credits: How They Shape The Grid

Table 8  |  Download Table

History Of The Production Tax Credit
YearLegislationProduction tax creditExpired
1992Energy Policy Act of 19921.5 cents/kWhDec. 1999
2000Extension1.5 cents/kWhDec. 2001
2002Job Creation Worker Assistance Act1.5 cents/kWhDec. 2003
2004American Jobs Creation Act1.5 cents /kWhExtended before expiration several times
2009American Recovery and Reinvestment Act2.1 cents/kWhDec. 2012 then extended in Dec. 2013
2015American Opportunity Tax Credit2.3 cents/kWhDec. 2020

The production tax credit (PTC) for wind power was passed into law in 1992 through the Energy Policy Act and, still today, offers producers 2.3 cents per kilowatt-hour electricity generated (see chart 5 and table 8). Despite being the major driver of wind power installations, the PTC has always been a source of unease and uncertainty for developers and investors alike, as uncertainty has often abounded around its renewal. Between 2007 and 2014, wind capacity quadrupled as the cost of generating electricity fell over 40%. Periods of sharp growth, however, were always shadowed by impending PTC expirations. Yet the threat of expiration of the PTC may have, ironically, prompted spikes in development.

Expirations resulted in layoffs, downsizings, and uncertainty surrounding future viability of wind power. Because it can take years to secure funding and negotiate power purchase agreements, a one-year PTC extension (of which there were several) was cause for a sigh of relief rather than a toast for anyone aligned with the success of wind generation. By 2015, 4.7% of electricity generated in the U.S. came from wind turbines, whereas across the Atlantic in Germany, wind power accounted for 13.3% of total output. However, the experience of the German wind market may provide a lesson for similar development in the U.S.

Studying Abroad

In 1991, a year before the American PTC, Germany created the first ever renewable energy subsidy in the world in the form of a feed-in-tariff (FIT) offering long-term, fixed-price contracts to renewable energy producers that utility companies were obliged to honor.

The FIT was modified several times, most significantly in 2000 when it was replaced by the Renewable Energy Sources Act. But unlike in the U.S., the tariffs never came with expiration dates, so German developers could count on reliable cash flows with no exposure to energy prices or fear that parliament would void their contracts. The inability to count on this steady growth in the U.S. can weaken credit quality, especially for project developers and yieldcos that depend on a steady flow of new development.

While the FIT produced strong growth in renewable capacity in Germany, it introduced a new challenge for utilities and merchant power producers. By 2013, particularly windy days would cause the grid to become dangerously overloaded and wholesale electricity prices plummeted so severely that on one occasion generators were charged €100 per megawatt-hour for their energy (see chart 6). Renewable energy producers have no marginal cost to generating additional power and they are given priority over fossil fuel generators in Germany so coal and gas plants have been the ones to suffer from oversupply.

While the FIT for wind was reduced according to schedule in Germany and utilities were saddled with the expense, legislators in Spain and Nevada chose a different method for recouping these costs. In Spain, retroactive caps on renewable generation and eventually a 7% tax on renewables was imposed in 2012. In Nevada, public utility commissions effectively squashed the market for residential solar by retroactively charging a fee and reducing the net metering credit so that it more or less equaled wholesale energy prices. After much unrest, the order was revised a year later in 2016 so that 32,000 customers were grandfathered in, but there are still no residential solar incentives.

Ultimately, as the share of electricity on the grid generated from renewables increases, utilities and lawmakers now recognize that their intermittency becomes more and more of a challenge. Until battery storage technology improves, the unpopular reality is that fossil fuels are still needed to keep the lights on at night or when the wind isn't blowing.

If policy has not been supportive, at least at the federal level, the question remains: Why has there been such substantial growth, and why are we poised for so much more? Our opinion is that diminished costs of installation, perhaps driven by renewable standards, have contributed to the rise of renewables in the U.S. This seems very unlikely to change going forward, even as uncertainty lingers about federal policy. Renewable costs that move wind and solar to grid parity with conventional generation may be motivated by competitive market factors, but is likely to dovetail nicely with broader efforts to cut greenhouse gas emission. To the extent that lower-rated unregulated generators are involved in these transactions (the yieldcos being a prime example), the likelihood of a palpable benefit in the spread is greater, even though the benefits from green issuance in the market to date have been largely anecdotal.

What's Next

So what does this suggest for renewable energy development in the U.S. going forward? In short, the development and expansion of renewable portfolio standards in the U.S. in recent years, in our opinion, crowds out a mixed message from Washington on the necessity of renewable energy as part of the American grid. As long as the marginal cost of renewable generation remains negligible, federal efforts to revive languishing coal and nuclear assets may prove fruitless; as the recent Department of Energy study shows, it's not even clear how much federal policy can do to help legally. Moreover, as long as state policies support renewables, even the cheapest of baseload nuclear reactors are unlikely to displace them. Our outlook continues to be bolstered by declining prices for installed generation, which reflects U.S. innovation and substantial state incentives. So strong is this ethos that it has consumed a new asset class. Massachusetts and Maryland both have made major investments in the infrastructure for developing offshore wind, as both states seek to bring jobs in a growth industry to their people, while we expect California to be a major hub for battery storage, driven equally by innovation and necessity, the latter due to increasing quantities of solar power in the state.

Regardless of what federal policy is signaling, there continues to be several factors driving increased decarbonization--and thus a possible increase in green bond issues--that aren't likely to abate in the near term:

Coal to gas switching

In the ongoing diminished gas pricing environment, we'd expect coal to continue exiting the dispatch stack. This is already well underway in unregulated, competitive markets and even absent a carbon mandate at the federal level, will continue as maintenance decisions become more dubious and cash flows weaken.

Demand interruption

In rating merchant power producers in the U.S. during recent years, one of the most unexpected patterns has been a slowing demand for electricity. This has happened for a myriad of reasons: a weaker economic recovery, better consumer awareness about energy use, more intermittent net demand driven by renewables, and the ongoing shift to a service-based economy from a manufacturing-based one.

Decentralization

We've also seen a shift to a utility model that employs greater distributed and renewable power generation and away from the classical utility model. That change means a requirement for fewer baseload generators. After all, a grid where demand patterns are less certain needs more flexible power generation, and baseload coal and nuclear generators don't support this. However, it may continue to create demand for peaking, pure capacity type resources, which could have an impact on capacity markets. While distributed generation currently lingers at about 1% penetration nationwide, and community choice aggregation (CCA) has sprung up only in small pockets of the country, both potentially could have severe implications for incumbent generators if they proliferate to a greater degree in coming years.

Renewable costs

Renewable growth has contributed to the increasing intermittency of the grid. The intended consequence of this was driving down costs, and this has certainly been achieved; in addition, as we've noted previously, we believe that successes in decreasing the installed costs on onshore wind and solar photovoltaic generation will help usher in the next generation of renewable technologies. What remains to be seen, however, is whether similar incentives for battery storage (still a nascent market) in more progressive states will have the same impact. We'll tackle this subject in an upcoming article, but what remains clear to us is that cost competitiveness continues to introduce new threats to conventional generation.

The Official U.S. Energy Outlook

According to the U.S. Energy Information Administration (EIA) annual energy outlook (Jan. 5, 2017) a modest recovery of natural gas prices from 2016-2020 will create favorable economics for electricity generation from coal vis à vis electricity generation from gas. After 2020, the EIA has different scenarios for economic growth, oil prices, technological development, and energy policies.

The EIA's base case, or reference case, assumes that energy consumption increases by 5% from 2016-2040 (see chart 7). The reference case also assumes that the Clean Power Plan (CPP) is implemented, causing states to cut carbon dioxide emissions from existing fossil fuel generation plants. As a result of the CPP and federal tax credits for renewable energy, renewable and natural gas generation increase significantly, overtaking coal generation by 2030.

Without the implementation of the CPP, however, the EIA forecasts that, all else being the same, renewable and natural gas generation will grow less dramatically. Natural gas generation still overtakes coal generation on a permanent basis, but now it would occur by 2035 rather than by 2030. Notably, this already happens periodically because this dynamic is highly sensitive to gas pricing. Similarly, renewable generation starts to converge with, but does not overtake, coal generation by 2040. This, of course is a consequence of the gradual retirement of coal assets, which we expect to occur as a result of shifting economics. Of course, this introduces questions about how utilities and IPPs are going to replace these assets (if at all), and how they will fund this transformation. These are all components of credit analysis for issuers that are disrupted as the shape of the grid changes.

In both cases, solar and wind drive growth in renewable energy generation. Most wind capacity additions take place before 2023, when production tax credits for wind plants are set to expire. Solar generation grows throughout the period, encouraged by state RPS, a 10% investment tax credit, and improvements in operational efficiency. But the expiration of these tax credits is not guaranteed and is subject to significant political machinations. Renewable energy, after all, often means new jobs, and that possibility resonates across the political spectrum as, even if the major parties in the U.S. have fundamentally different views on climate change and support for the the maturing renewables sector.

Along these lines, wind and solar capacity increase by almost 70 GW between 2017 and 2021 in the reference case (see chart 8). In the longer term, solar and natural gas dominate new generation capacity additions. Between 2030 and 2040, solar comprises over 50% of capacity additions. Meanwhile, fossil fuel generation units continue to retire.

As natural gas and renewables surpass coal in electricity generation, carbon dioxide (CO2) emissions from electric power decline. Accordingly, emissions from the petroleum-dependent transportation sector exceeded emissions from the electric power sector for the first time in 2016. To date, the reduction in carbon emissions has been largely economically driven.

Nevertheless, when considered as a whole, energy-related CO2 emissions are slated to decline less than in previous years; 0.2% annually between 2016 and 2040, versus 1.4% annually between 2005 and 2016 (see chart 10). Heightened industrial energy use and emissions driven by industrial growth are the primary causes of slowed emissions reduction. This stems largely from a recovery in the economy, though the connection between energy demand and GDP growth has diminished substantially in recent years as the U.S. has transformed into a service-based economy. As gas prices stay low, renewables penetrate, and demand slackens, we are unlikely to reach the carbon emissions peak seen around 2005. Sustained reduction in carbon emissions, however, would likely require a more comprehensive program rather than a collection of state by state policies. We continue to anticipate that this will not occur because the U.S. has said it will leave the Paris Agreement, although the legality of doing so before 2020 remains in question.

While CO2 emissions decrease slowly in absolute terms, carbon and energy intensity decrease significantly by 2040. Energy intensity, quantified as the number of thousand Btus of energy used to generate one dollar of economic growth, decreases by 37% between 2016 and 2040 in the reference case. During the same period, carbon intensity, quantified as the number of metric tons of CO2 emitted per billion Btus of energy consumed, decreases by 10%.

Taken together, these factors are likely to continue to put pressure on the IPPs, which historically have been more focused on conventional generation and have been ceding ground to renewable generation. Two major trends that appear irreversible in the near term--cleaner energy and weaker power pricing--have meant weaker credit quality and higher leverage for American IPPs. As the grid becomes greener and more intermittent, we expect these credit trends to continue, unless shrewd management teams can find mitigating measures. And as the grid transforms, we'll continue to analyze how it affects all the participants in the power generating business (see chart 11). In a coming piece on smart cities, we'll discuss some of these more grassroots initiatives, and the impacts community choice aggregration could have on generators in the U.S.

Notes

1 National Conference of State Legislatures (NCSL). State Renewable Portfolio Standards and Goals. (Raleigh, N.C. State University, August 2017). http://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.

2 NCSL 2017.

3 Clean Energy States Alliance (CESA). Designing the Right RPS: A Guide to Selecting Goals and Program Options for a Renewable Portfolio Standard. Prepared March 2012 for the State-Federal RPS Collaborative and the National Association of Regulatory Utility Commissioners. p. 40. https://energy.gov/eere/slsc/downloads/designing-right-rps-guide-selecting-goals-and-program-options-renewable.

4 NCSL 2017.

5 CESA 2012, p. 41.

6 NCSL 2017.

7 Galen Barbose. Lawrence Berkeley National Laboratory. U.S. Renewables Portfolio Standards: 2017 Annual Status Report. July 2017. https://emp.lbl.gov/sites/default/files/2017-annual-rps-summary-report.pdf.

8 Ibid.

9 Ibid.

10 Ibid.


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