Electricity demand is increasing, and so are electricity costs for households and businesses across the United States. After more than two decades of relatively flat electricity demand growth, the near-term surge in new demand from “hyperscale” AI data centers is poised to send electricity prices through the roof without strong ratepayer protections and other policy interventions.

Addressing these new threats from data centers—alongside existing price drivers such as increasing fossil gas prices and the high upfront cost of necessary infrastructure upgrades in the face of climate-fueled extreme weather—will require concerted efforts to address both electricity demand and supply. Unfortunately, actions taken during the first year of the Trump administration are moving us in the wrong direction and could result in much greater increases in electricity costs, while also risking more outages, more pollution, and more climate-damaging emissions. A new analysis from the Union of Concerned Scientists (UCS), Data Center Power Play, makes clear just how much is at stake, finding that:

• Data center demand is highly uncertain, but will be the greatest near-term driver of load growth
• Current policies risk putting the United States on a path to meet much of this demand with fossil fuels
• Stronger policies can shift our path to running primarily on renewables without sacrificing reliability, while also bringing important health and climate benefits
• The looming data center-driven demand surge comes with significant costs across all scenarios, and policymakers must take steps to ensure that these costs are not passed on to consumers

Overall, our modeling demonstrates that clean and renewable energy can meet the challenge of load growth from data centers, but policymakers must be proactive to protect our health, environment, and financial interests. 

Trump admin sidelines clean energy amid rising electricity demand

Even as the Trump administration boasts of leading the global AI race, it is sidelining the clean, plentiful, affordable, and efficient energy technologies that are best poised to power such a future.

Even with investments in energy efficiency—which the Trump administration is aggressively undermining—we will still need to significantly increase electricity generation to meet surging demand growth from data centers and electrification. This will require building as much new, low-cost capacity as quickly as possible, and making it as clean as possible to avoid negative climate, health, and environmental impacts. Here, renewable energy technologies, especially solar and wind combined with energy storage, check all the boxes. They have a distinct advantage over fossil fuels and low carbon technologies such as new nuclear and carbon capture and storage (CCS), which have long lead times, high costs, and are largely unproven technologies.

Combining wind and solar with battery storage, while requiring greater data center flexibility, offers a promising solution for powering data centers and meeting overall electricity demand. Over the past few years, the vast majority of new capacity additions in the United States, and globally, have been wind, solar, and battery storage. These technologies also dominate new capacity waiting to be developed in transmission interconnection queues.

Further, the costs for wind and solar have fallen 70 to 90% over the last 15 years, making them cheaper in many cases than new gas and existing coal plants, even without subsidies and before factoring in environmental and health benefits. The lead time to plan and build wind and solar projects is also much shorter than it is for new gas or nuclear plants. In addition, recent studies have identified demand-side flexibility at data centers as an important strategy for reducing peak demand and lowering costs.

In striking contrast to this forward momentum is the Trump administration’s stated preference for using dirty, outdated fossil fuel generation to power emerging technology. At the same time, it has created significant headwinds for wind, solar, and storage, including rolling back federal tax credits, illegally rescinding clean energy grants and financing approved by Congress and under contract, illegally halting offshore wind and other renewable energy projects that are either under construction or fully permitted after lengthy reviews, blocking new wind and solar permitting from moving forward, and more.

The stakes are high. The path that states and the nation choose on how to power data centers has wide-ranging implications for energy affordability, reliability, public health, the climate, and the economy as a whole.

Powering data centers with clean energy vs. fossil fuels

To better understand the potential impacts of meeting US electricity demand growth from AI data centers, UCS’s new analysis highlights the consequences of data centers’ growing electricity demand on the US power grid and how decisionmakers can mitigate harmful economic, climate, and health impacts through clean energy deployment and strong ratepayer protections.

Using the National Renewable Energy Laboratory’s (which the Trump Administration recently renamed the National Laboratory of the Rockies) open-source  Regional Energy Deployment System’s (ReEDS) power sector model, we analyzed the impacts of meeting electricity demand growth from AI data centers on electricity generation, electricity costs, and the health and climate costs of emissions from using fossil fuels—as well as the avoided health and climate costs of emissions from using clean energy instead. Since future data center demand growth and the policy landscape are highly uncertain, we modeled multiple demand growth and energy policy scenarios.

Data center demand is surging—and highly uncertain

We project overall US electricity demand to increase 62% between 2025 and 2050 under a “mid-level” data center demand growth scenario, and as much as 79% under a “high” data center demand growth scenario (Figure 1). Data centers account for about half of total demand growth over the next five years, but this share falls over time as electrification increases in other sectors (especially transportation). While we vary the amount of data center demand growth, we assumed the same level of demand growth in other sectors under all scenarios. Studies by UCS and others show that higher levels of electrification of other sectors would likely be needed to achieve economy-wide net zero emissions by 2050.  

The number of data centers anticipated to be built in the United States and how much
electricity they will need are both highly uncertain. Recent actions by electric
utilities and regional transmission organizations indicate that many proposals to build data centers are redundant. In addition, utilities, which earn a guaranteed return on investment, have an incentive to overestimate future demand. This could lead to overbuilding the electricity system, higher costs, and stranded assets. A lack of transparency compounds the uncertainties, as proposals to build data centers and the power plants to serve them, are typically confidential.

Current policies increase reliance on fossil fuels

Under current state and federal climate and energy policies, our analysis finds that the United States is likely to increase its reliance on fossil fuels as electricity demand grows due to data centers and electrification of other sectors. We found that gas generation could increase 23% between 2026 and 2035 and 77% by 2050, with 90 gigawatts (GW) of new gas capacity added by 2035 and a whopping 335 GW by 2050. (One gigawatt is enough to power about 750,000 average US homes per year and could be supplied by 294 utility-scale land based wind turbines, according to DOE)

While our analysis projects coal generation to continue to decline in response to planned retirements, remaining coal plants are dispatched more to help meet the growth in demand. While the model includes the Trump administration’s rollbacks of EPA power plant carbon standards, we didn’t account for other regulatory rollbacks and subsidies that could further boost coal generation. For example, we didn’t model recent Trump Administration actions to use emergency powers to prevent at least six uneconomic coal plants from retiring, which are expected to increase electricity costs for consumers.

Even with these caveats, we found that the additional fossil fuels burned to power data centers could increase power plant carbon dioxide (CO₂) emissions by 19% and result in $1.6 trillion in climate and health damages over the next decade, growing to $4.5 trillion by 2050, under our mid-level data center demand growth scenario. We expect that recent actions not included in the model would only increase these costs compared to our results.

Stronger policies ensure that clean energy powers data centers

Restoring federal clean energy tax credits accelerates the deployment of wind and solar to power data centers. It also reduces reliance on gas and coal generation to meet the growth in electricity demand.

Adopting policies to reduce US power sector emissions of CO₂ would go even further, facilitating the clean energy transition to help meet economywide emission reduction targets. With a target of a 95% reduction in CO₂ below 2026 levels by 2050, wind and solar generation nearly triple between 2026 and 2035 and increase five-fold by 2050 to replace coal and gas. Combined, all renewable energy sources provide more than 60% of total US electricity generation by 2035 and 81% by 2050.

Data centers put ratepayers at risk of higher electricity costs

Rapid data center growth results in more than $500 billion in cumulative electricity costs nationally by 2035 and nearly $1 trillion by 2050 across our three policy scenarios and assuming mid-level demand growth. This represents 18-24 percent of total US wholesale electricity costs over the same period (see Figure 5). Without strong ratepayer protections requiring Big Tech companies to pay their fair share, these costs could get passed onto households and other businesses.

Restoring federal clean energy tax credits to the timelines and phaseouts that were included in the Inflation Reduction Act results in cumulative savings of $248 billion (4 percent) through 2050 compared with the “Current Policies” scenario. This underscores that recent actions by Congress and President Trump to rollback tax credits for solar and wind as part of the One Big Beautiful Bill Act (OBBBA) will make electricity less affordable, which is consistent with other recent studies.

Restoring the tax credits and adopting more ambitious climate and clean energy policies that nearly decarbonize the power sector by 2050 (the Low-Carbon Policy scenario) results in higher costs of $291 billion (12 percent) from 2026 to 2035 and $412 billion (7 percent) through 2050 compared with Current Policies. But these costs of transitioning to clean, low carbon energy sources are far outweighed by the avoided climate and health damages from burning fossil fuels, reaching more than $1.6 trillion between 2026 and 2035 and $13.3 trillion by 2050. Additional interventions, such as using clean electricity to replace fossil fuel use in other sectors, investing in energy efficiency, and increasing data center flexibility, could significantly lower overall energy bills.

We can avoid the health and environmental harms associated with unmitigated growth of data centers

Ensuring that data centers are efficient, flexible, and powered with clean energy requires stronger state and federal policies. Policymakers and regulators should require utilities and data center developers to be more transparent and accountable, improve long-term planning for meeting data center demand, and protect other customers from cost increases and negative health impacts.

They should also require utilities and data center developers to meet demand growth with new low carbon or zero carbon generation and use energy storage instead of diesel or gas generation for back-up power. Policies supporting the development of data centers should include standards and guardrails that protect public health while reducing emissions, energy and water use, and other environmental impacts.

Only bold action will ensure that the nation meets electricity demand growth with clean energy, achieves its climate goals, and protects consumers from added costs brought on by the growth of data centers. Unmitigated data center growth should not continue in the absence of stronger policies and guardrails, given that the consequences for energy affordability, reliability, public health and the climate are so high.  The path for the United States to achieve these benefits is clear.

The bill (LD 1868), passed by the Maine Legislature on June 13, will reduce the state’s reliance on imported fossil fuels by requiring all of Maine’s power to come from renewable energy and other carbon-free electricity sources by 2040. In addition to lower energy costs, the plan will create new jobs and investment in a rapidly growing clean energy industry. Continuing to replace methane gas and oil use in homes, businesses, and vehicles with a growing supply of zero carbon electricity is also a critical component of meeting Maine’s climate goals.  

Governor Mills called for accelerating Maine’s clean electricity standard to 100% by 2040 in her 2023 State of the Budget Address when the state was facing extremely high fossil fuel prices following the Russian Invasion of Ukraine. She signed the bill into law on June 20, 2025. It was also a key recommendation in Maine’s 2024 Updated Climate Action Plan (that I helped develop as a member of the Energy Working Group) and the Maine Energy Plan the Governor’s Energy Office (GEO) submitted to the Legislature in January 2025. 

In addition to testifying, UCS worked with a broad coalition of groups representing clean energy and environmental advocates, businesses, labor, and other stakeholders to build support for the bill. 

What the bill would do 

In 2019, Maine passed several major climate and clean energy bills, including increasing its renewable portfolio standard (RPS) to 80% by 2030 and adopting a non-binding goal of 100% renewable electricity by 2050.  The current bill would further increase the RPS targets to 90% by 2040. The remaining 10% by 2040 could come from a wide range of low- and zero-carbon technologies, including nuclear power, large existing hydropower projects, and using so-called “clean” fuels like biomethane or hydrogen in thermal plants.  

However, an analysis commissioned by the Governor’s Energy Office—Pathways to 2040—showed that renewable energy sources (primarily new wind and solar) would provide nearly all of the electricity generation needed to meet Maine’s 100% clean electricity targets by 2040 because they are cheaper to deploy than these other sources. 

The bill goes hand in hand with another bill (LD 1270) recently passed by the legislature, which would replace the Governor’s Energy Office with a cabinet-level Department of Energy Resources that has the responsibility to conduct competitive procurements to ensure Maine’s clean electricity targets are met in a timely and cost-effective fashion. 

Increasing clean energy is affordable 

The two main drivers for recent electricity cost increases are Maine’s and New England’s over-dependence on imported methane gas for more than half of the region’s electricity and the increase in climate change-fueled extreme weather events. High gas prices, due in large part to the Russian war in Ukraine and decisions by the US and other countries to ban Russian oil and gas imports, increased average residential electricity bills in Maine by $60 per month between 2021 and 2023.  

In addition, CMP storm recovery costs totaling $220 million for three storms in 2024 added $10 per month to residential bills. 

Recent studies and the results of past RPS procurements provide compelling evidence that accelerating Maine’s clean electricity targets to 100% by 2040 could offset these drivers and help lower overall energy costs: 

• The Maine Pathways to 2040 study shows that achieving 100% clean electricity by 2040, combined with widespread electrification of transportation and heating, could reduce electricity prices and average household energy costs by 20 percent, or more than $1,300 per year.  

• Maine’s RPS has already saved ratepayers an average of $21.5 million per year between 2011 and 2022, according to a 2024 analysis commissioned by GEO.  

• Data from the Maine Public Utilities Commission (PUC) shows that past renewable energy procurements under Maine’s RPS have driven generation costs down, resulting in lower customer electricity bills. The sale of energy from approved procurements played a key role in reducing delivery prices for Central Maine Power (CMP) residential customers by 5.5% and for Versant residential customers by up to 3.8% in 2022, while helping to offset high storm recovery costs seen in 2020 and 2021. 

• State RPSs have been a key driver for renewable energy deployment in the United States, contributing to major cost reductions for wind and solar. National average power purchase agreement (PPA) prices for wind fell by nearly 70% between 2009 and 2022, while PPA prices for utility-scale solar projects fell by 87% between 2010 and 2023, according to Lawrence Berkeley National Laboratory (LBNL). State RPSs, combined with long-term procurement policies, have also provided stability and predictability for renewable energy developers that have helped lower the cost of financing projects. 

Creating new jobs and economic development 

Maine spends more than $4 billion per year on imported fossil fuels. Using this money to invest in energy efficiency and cleaner, homegrown energy sources will create new high-quality jobs and grow Maine’s economy, while increasing energy independence and energy security. For example: 

• Maine’s RPS has resulted in over $100 million in direct investment, $900 million in operations and maintenance spending, over 1,000 full-time equivalent (FTE) jobs, and over $1 billion in worker income between 2008 and 2022. 

• Maine’s clean energy economy grew more than three times faster than its overall economy between 2016 and 2022. Clean energy jobs in Maine have bounced back from COVID-19 disruptions and are back on the pathway to reach Governor Mills’ goal of supporting 30,000 clean energy jobs by 2030. 

Maine is a clean energy leader 

Adopting a 100% clean electricity standard by 2040 would solidify Maine’s role as a clean energy leader. As of August 2024, 29 states and the District Columbia have adopted RPSs and CESs, according to LBNL. Sixteen states, including Maine, have RPS targets of at least 50% of retail sales, four states have adopted 100% RPSs, and 16 states have broader 100% CESs that reach these targets between 2040 and 2050. The policy has been so successful that many states, including Maine, have continued to strengthen their targets over the past 20 years. 

Maine is also showing that states can continue to make progress in the face of the relentless attacks on clean energy at the federal level. While proposals to slash federal clean energy incentives could raise electricity bills and slow progress in the short-term, continued investment by the states and other countries will continue to drive down the costs of clean energy at the global level. It will also be critical in lowering the mounting costs of climate change and public health impacts from burning fossil fuels. 

We applaud the Maine legislature and Governor Mills for passing strong clean energy legislation that recognizes the urgency of the climate crisis and sets an important example for other states to follow. 

Editor’s Note: Governor Mills signed this bill into law on June 20, 2025. The blog has been updated to reflect this.

But gas power plants have also played an important role in helping to maintain the overall reliability of the electricity grid by meeting peak power demands, such as on hot summer days when people turn on their air conditioners. However, as we replace fossil fuels with clean electricity for heating and transportation to meet our climate goals, these peak demands will increasingly shift to the winter in many parts of the country. In addition, recent extreme weather events have shown that gas plants aren’t as reliable as utilities and grid operators have been assuming, especially during the winter.  And this problem will only get worse as the impacts of climate change become more frequent and severe.

While it’s clear we need to rapidly reduce gas generation to help limit the worst impacts of climate change, it’s less clear how much fossil gas capacity we actually need to maintain reliability in a future decarbonized grid. It’s worth delving into because it has some important implications for our clean energy future.

Sharp reductions needed in gas generation to meet US climate goals

Under the Paris Agreement, the United States has committed to reducing heat-trapping emissions to 50-52 percent below 2005 levels by 2030 and to reaching net zero emissions no later than 2050. Recent UCS modeling, conducted in partnership with Evolved Energy Research (EER), shows that, to reach these goals means completely phasing out US coal generation by 2030; in this scenario, gas generation would fall from about 40 percent of US electricity generation in 2021 to 25 percent in 2030, and 2 percent in 2050 (see figure 1).

Figure 1. US Electricity Generation

Wind and solar lead the way in decarbonizing the power sector to meet near-term climate targets. Decarbonizing the power sector also plays a critical long-term role by replacing fossil fuels in other sectors. Source: UCS Accelerating Clean Energy Ambition.

In this plan, almost all of this coal and gas generation is replaced with wind and solar. Wind, solar, and other renewables nearly triple, from 22 percent of US electricity generation in 2021 to 60 percent in 2030 and continue to increase to 92 percent in 2050 under our Net Zero Pathway. The remaining 6 percent of US electricity generation that does not come from gas or renewables is projected to come from existing nuclear plants.

Most of the near-term deployment of wind and solar is driven by incentives in the Inflation Reduction Act (IRA) and existing state clean energy policies, as shown on the left of the graph. But after the IRA incentives expire in the early 2030s, we see gas and coal generation rebounding and US heat-trapping emissions flattening out. The exact impact of the IRA tax credits is uncertain and depends heavily on the rate at which wind, solar, energy storage, and transmission can be built over the next decade.

A very different role for gas in a decarbonized energy system

Our modeling shows that, while gas generation declines to de minimis levels by 2050 to meet US climate goals, gas capacity does not change much over time in order to help maintain reliability during periods of unusually low renewable generation (see figure 2). Some older gas and oil plants are replaced with more efficient plants during the near-term transition away from fossil fuels to wind and solar. A small amount of gas with carbon capture and storage (CCS) capacity (~10 gigawatts) is also added to help meet the 2030 emission reduction target and to take advantage of generous incentives for CCS in the IRA.

Figure 2. US Electric Generation Capacity under the Net Zero Pathway

While gas capacity stays relatively fixed over time, its share of total US electric capacity falls from 44 percent in 2021 to 11 percent in 2050 under the Net Zero Pathway, as electricity demand more than triples to replace fossil fuels with clean electricity in the transportation, buildings, and industrial sectors. Wind, solar, energy storage, and transmission provide the vast majority of new capacity additions, which demonstrates that these technologies play a significant and growing role in maintaining grid reliability in the future.

Importantly, though, overall use of that gas capacity dramatically declines over time. By 2050, gas plants operate at less than 6 percent of their rated capacity during the year compared to more than 38 percent for all gas plants in 2022, according to the Energy Information Administration (EIA).

These results are consistent with other decarbonization studies. For example, a 2023 National Renewable Energy Laboratory (NREL) study found that, to meet President Biden’s goal of achieving 100 percent clean electricity by 2035, gas generation would decline to 4 percent of US electricity generation but would provide 21 percent of total electricity capacity (see figure 3). (NREL also found that the emissions resulting from the remaining gas generation would be offset through the deployment of negative emissions technologies such as bioenergy with CCS and direct air capture with CCS).

Figure 3. US electricity capacity and generation under NREL’s All Options scenario in 2035

NREL’s modeling of reaching 100 percent clean electricity by 2035 shows a significant reduction in gas generation but maintains a significant dependence on gas capacity to provide peaking capacity and ensure resource adequacy during the clean energy transition. Source: NREL, 100% Clean Electricity by 2035 study.

Models overestimate the reliability of gas plants

While many grid modeling analyses examining a deeply decarbonized grid demonstrate a need to keep a large amount of gas capacity online, the catch is that most models overestimate the reliability of gas plants. These models often rely on methods adopted in regional electricity markets that don’t account for the systemic and widespread gas plant outages and other gas system failures that have occurred during extreme weather events fueled by climate change. While gas plant failures have been worse in the winter, problems have also occurred during the summer because of extreme heat and drought.

As highlighted in our recent Gas Malfunction report, these failures have led to rolling blackouts, which have caused serious health and safety consequences for communities left without power during critical times of need. It also means that gas plants have been overcompensated for their reliability services, putting other cleaner alternatives at an economic disadvantage and increasing costs to ratepayers. Gas plants failed disproportionately compared to other resource types in five extreme winter weather events, as shown in Figure 4.

Figure 4. Generation Failures by Fuel Type During Five Extreme Winter Storms

Gas plants accounted for most of the failed capacity in five recent extreme winter events. Gas plants failed disproportionately in comparison to gas’s percentage of total installed capacity, indicating they are more susceptible to extreme winter weather than other resource types. Source: UCS, Gas Malfunction

Recognizing the reliability threats gas power plants pose to the energy grid, a group of Regional Transmission Organizations (RTOs) recently published a joint position paper calling for improved gas-electric coordination.

Like other models, EER’s model assumes that, on average, 95 percent of a gas plant’s installed capacity is available to generate electricity at any given time and counts towards reliability. In industry parlance, this means it has an equivalent “forced outage rate” of 5 percent. NREL’s Regional Energy Deployment System (ReEDS) model is even more optimistic, assuming gas plants (and other conventional generators such as coal and nuclear) have a capacity credit of 100 percent.

Regional electricity markets that use similar numbers typically assume forced outages are completely independent of each other. This is a problem because such low forced outage rates don’t reflect the reality of gas plant performance during extreme weather. It also ignores the reality that gas power plant failures correlate with outages that occur in extreme weather. (For more details on how programs have been significantly overvaluing the reliability contributions of gas power plants, see this blog by my colleague Mark Specht). 

A 2022 Astrape Consulting study that used probabilistic methods to account for the risks of correlated power plants outages found a capacity credit for gas (in PJM South) of 76 percent in winter and 85 percent in summer. And this North American Electric Reliability Corporation (NERC) report evaluating the impacts of the 2014 Polar Vortex shows forced outage rates for gas in January reached nearly 40 percent in some regions.

Reducing the reliability risks of an overreliance on gas

Fossil gas will certainly have a role to play in helping to meet peak demand even as we move to a decarbonized electricity grid. But the latest research and modeling suggests that it’s time to reassess how large a role that should be.

Nearly all grid modeling to date has assumed that gas plants are much more reliable than they actually are. We’ve started to see studies that shed light on how well gas plants perform, and they’re not meeting current expectations. So, we need to adjust our grid modeling to use realistic assumptions about gas plant contributions to grid reliability—both to ensure power system reliability and to make sure our modeling isn’t biased towards picking gas plants for grid reliability when they aren’t sufficiently performing that service.

One of the implications of this shift is that we need to consider alternatives to gas-fired plants that can reduce these risks and provide similar reliability services. While nuclear power, or gas with CCS could play a role providing these services, these technologies pose other significant cost, performance, and safety risks.  Other cleaner and less risky alternatives—such as long-duration storage, geothermal energy, concentrating solar power with storage, and green hydrogen—could play an increasing role in meeting seasonal needs while also helping to address the performance issues gas plants have recently displayed during extreme weather events.  

The newly updated legislation (LD 1895), which the legislature is considering this week, builds on recommendations from Maine’s Offshore Wind Roadmap and policies adopted by other leading states. It would require the Maine Public Utilities Commission (PUC) to conduct a competitive bidding process to procure 1,000 megawatts (MW) of offshore wind capacity by 2030 and 2,800 MW by 2035, enough to generate more than half of Maine’s electricity demand. Meeting these targets would strengthen Maine’s economy by creating high-quality jobs and helping stabilize energy costs. LD 1895 also would ensure that offshore wind is developed responsibly and equitably in the Gulf of Maine.

Here are five reasons why LD 1895 is so important for Maine:

Offshore wind is critical to achieve Maine’s climate and energy goals

Maine’s climate and clean energy laws are well-aligned with science-based targets for reducing heat-trapping emissions, and a recent Union of Concerned Scientists (UCS) report noted that Maine has one of the strongest climate action plans in New England.

That said, offshore wind development will be critical to meet state and regional climate and clean energy requirements. Recent studies project that offshore wind development in Maine could range from 500 MW to 1,000 MW in 2030 to 5,000 MW to 8,000 MW by 2050 (see reports by DNV, Evolved Energy Research, Synapse, E3 and Silkman).

With 2,800 MW installed and operating by 2040, offshore wind would provide more than half of Maine’s electricity demand, even if the state’s demand more than doubled as the state moves to replace fossil fuels with clean electricity for transportation and heating.

Procurement targets are an effective tool

More than two decades of adopting and implementing renewable electricity standards in 30 states shows that procurement targets have been a key driver for deploying land-based wind and solar, achieving economies of scale, increasing technology innovation, and lowering costs.

At least 10 other states, including six in the Northeast, have adopted offshore wind procurement targets totaling 81,000 MW over the next 20 years, according to the American Clean Power Association (ACP). These targets range from 1,400 MW by 2030 in Rhode Island to 11,000 MW by 2040 in New Jersey to 25,000 MW by 2045 in California. While LD 1895’s 2,800 MW by 2035 procurement target is more modest, most of the other states with higher targets have much larger populations and greater energy demand. Most states also have interim targets that ramp up over time, which gives the industry more investment certainty and will be necessary to build out the offshore wind supply chain.

Adopting a procurement requirement would give Maine a much better chance to compete in the race with other states to develop offshore wind and related supply chain infrastructure. According to ACP, more than 51,000 MW of offshore wind is currently under development in the United States, 84 percent of which is on the East Coast. This includes 938 MW currently under construction, 18 projects in advanced development representing 16,564 MW, and 18 projects in early development totaling 33,875 MW. While only a few floating offshore wind projects are currently operating globally, the development pipeline more than doubled over the past year from 91,000 MW from 120 projects to 185,000 MW from 230 projects.

Developing floating offshore wind projects in the Gulf of Maine will be important to meet state and regional targets and build on the University of Maine’s leadership in developing the technology. While floating offshore wind is more challenging to develop than fixed-bottom projects, the Gulf of Maine has the highest, most consistent wind speeds on the East Coast. According to the National Renewable Energy Laboratory (NREL), floating offshore wind represents 63 percent of the total technical potential for offshore wind in the North Atlantic and 65 percent at the national level.

Maine can capitalize on falling costs and federal incentives

Like land-based wind and solar photovoltaics, the cost of offshore wind is projected to fall rapidly over time as the technology matures and the supply chain grows. The cost of fixed-bottom offshore wind projects has already fallen by 48 percent, from $162 per megawatt-hour (MWh) in 2010 to $84/MWh in 2021, due to development in other countries.

While the costs of floating offshore wind projects are currently higher than fixed-bottom projects, they are projected to be similar by 2035. NREL and DNV expect floating offshore wind costs to dip to $60 to $80/MWh by 2030 and $45 to $50/MWh by 2035. The Biden administration, which set a goal of 15,000 MW of floating offshore wind by 2035, also has set a price target for floating offshore wind power at $45/MWh by 2035, which is less than the cost of electricity from new natural gas plants.

Incentives in the historic federal climate bill passed last fall will help lower the costs even further. In fact, the timing of Maine’s offshore wind procurement targets in LD 1895 is designed to take advantage of federal tax credits, which could lower the capital costs of projects built in the Gulf of Maine by at least 30 percent. Funding also is available to help build out Maine’s supply chain and offshore wind component manufacturing, spur investments in port infrastructure, and encourage transmission planning.

While the cost of offshore wind projects has increased in the past two years due to inflation, rising commodity prices, and supply chain pressures, UCS expects these effects to be temporary. Land-based wind similarly experienced temporary cost increases during the 2008 economic recession. But since 2009, the cost of land-based wind has dropped by more than two-thirds as inflationary pressures eased, the technology advanced, and the US-based supply chain matured.

Offshore wind can help stabilize energy costs

In addition to becoming increasingly cost-competitive over time, offshore wind also can help stabilize energy costs for households and businesses by reducing regional reliance on imported gas and oil. Dependence on gas for about half of the power generation in New England resulted in an 83-percent supply-rate increase in Maine last year, and a 49-percent supply-rate increase this year, representing a $32 jump in a typical household’s monthly electricity bill. Offshore wind power has no fuel costs, so power costs are more stable and predictable over time than fossil fuel-fired power. Wind also can help protect ratepayers from price volatility caused by such events as the Russian war in Ukraine or extreme weather. Moreover, offshore wind also would produce more electricity during the winter heating months when New England energy demand is greatest.

Offshore wind development resulting from LD 1895 also could put downward pressure on electricity and gas prices—and save ratepayers money. Electricity generation is dispatched at the regional level according to increasing costs. Since wind and solar have no fuel costs and low operating costs, utilities typically dispatch them first. Gas generators, on the other hand, have relatively high fuel and operating costs, so utilities typically dispatch them last to meet demand, thereby setting the market price of electricity. Thus, by reducing the need for more expensive gas generators that are on the margin, offshore wind could lower wholesale electricity prices.

• For example, a 2020 NREL study found that deploying 7,000 MW of offshore wind in grid operator ISO-New England’s (ISO-NE) transmission area would reduce regional wholesale electricity prices by 13 percent and result in total electricity production cost savings of as much as 18 percent.

• An analysis by ISO-NE that found that if 1,600 MW of offshore wind had been online during the 2018 cold snap, New England consumers would have saved more than $80 million, carbon dioxide emissions would have been 11 percent lower, and more reserves would have been available to maintain a stronger reliability margin.

Ensuring responsible, equitable offshore wind development

As someone who lives in a small coastal fishing community near Maine’s Acadia National Park, I can see up close the importance of developing offshore wind in a responsible and equitable way that includes strong labor and environmental standards and protections for the fishing industry, local communities, and tribes. The project labor agreements and labor “peace” agreements in LD 1895 are supported by the BlueGreen Alliance (of which UCS is a founding member) and have been adopted by other states to ensure offshore wind projects are built with strong labor standards and are able to maximize federal incentives available through the Inflation Reduction Act and infrastructure laws.

LD 1895 wisely includes tax incentives that would encourage wind development outside of Lobster Management Area 1 and offset the modest additional costs of locating projects further offshore. In addition, the bill would provide funding for local fishing communities, which would create new jobs and tax revenue, and for independent scientific research to determine the best way for Maine to embrace the vast benefits of wind power while protecting wildlife, fisheries and the environment.

LD 1895 also guarantees a place at the table for federally recognized and state acknowledged tribes and would require developers to consult with tribes every step of the way. Further, the bill includes workforce development, employment, and contracting opportunities, as well as financial and technical assistance to support robust monitoring of the fisheries that local tribes care about most.

While these provisions are a good start, more engagement with the tribes is clearly needed to avoid, minimize, and compensate for any negative impacts from offshore wind development. Tribal nations must be included in the development, permitting, and management of offshore wind projects. Likewise, more data and research is needed to ensure impacts to cultural resources are adequately considered in the US Bureau of Ocean Energy Management’s suitability analysis to identify potential offshore wind leasing areas.

Pass this bill!

It’s time to make offshore wind a reality in Maine, and LD 1895 offers a path forward for responsible and equitable development of this key resource. If you’re a Maine resident, you can tell your state senator or representative to support LD 1895 by clicking here.

Critics of wind and solar routinely raise concerns about how much land would be required to decarbonize the US power sector. Fortunately, the answer is relatively little. A recent National Renewable Energy Laboratory (NREL) study shows that it would take less than 1 percent of the land in the Lower 48—that’s an area comparable to or even smaller than the fossil fuel industry’s current footprint. And when wind and solar projects are responsibly sited, the environmental and public health impacts would be far less harmful than those from extracting, producing and burning fossil fuels.

A key role for wind and solar

The fact that renewables will not require an inordinate amount of land is welcome news because limiting climate change’s worst impacts will require us to cut global heat-trapping emissions roughly in half by 2030 and to achieve net-zero emissions by 2050, according to the Intergovernmental Panel on Climate Change. Acknowledging that the United States is a leading contributor to carbon emissions, the Biden administration has committed to cutting US emissions 50 to 52 percent below 2005 levels by 2030.  Most studies show that achieving these targets will require an unprecedented increase in wind and solar power to decarbonize the power sector and meet the increased demand for zero- carbon electricity to replace fossil fuels in building, industrial and transportation sectors.

A 2022 NREL study found that, to achieve President Biden’s goal of generating 80 percent zero-carbon electricity by 2030 and 100 percent by 2035, we will need to increase wind and solar power from about 14 percent of the US electricity mix in 2022 to between 60 and 75 percent by 2035 under the main scenarios. When combined with modest increases in geothermal and hydropower capacity at existing unpowered dams and upgrades to existing facilities, renewable energy would provide 70 to 85 percent of total US electricity generation by 2035. NREL projects that most of the remaining generation would come from existing nuclear plants and a small amount from gas plants, carbon capture and storage, hydrogen and biogas.

NREL also found that meeting the growing demand for zero-carbon electricity means overall US generation capacity would need to roughly triple between 2020 and 2035, including a combined 2,000 gigawatts (GW) of wind and solar capacity. This would require growth rates in the range of 43 to 90 GW per year for solar and 70 to 145 GW per year for wind by the end of the decade, which would mean more than quadrupling the current annual deployment rates for each technology.

Although siting, permitting and ramping up manufacturing for all of this new wind and solar generation will be challenging in this time frame, NREL’s study and other studies suggest that it is technically and economically feasible. For example, about 930 GW of wind and solar capacity and 420 GW of storage projects are now awaiting approval to connect to the transmission system, according to Lawrence Berkeley National Lab. This year alone, developers are planning to install 29 GW of utility-scale solar. That’s more than double the current record and represents more than half of all new US capacity, according to recent Energy Information Administration (EIA) data.  EIA also projects US battery storage capacity to more than double in 2023.

The federal Inflation Reduction Act (IRA) also will make a big difference by making available hundreds of billions of dollars in new incentives for these technologies. NREL’s 2022 Standard Scenarios study found that these federal incentives would accelerate the deployment of wind and solar, helping to reduce US power sector carbon dioxide emissions to 80 percent below 2005 levels by 2030.

Comparatively small footprint

NREL found that the land area directly occupied by wind and solar infrastructure by 2035 would make up less than 1 percent of the land in 94 percent of the country and less than or equal to 7 percent of total land area in just three states. A key reason why a relatively small amount of land is needed is because only 2 percent of the total area within a wind farm is occupied by wind infrastructure, while the remaining 98 percent is available for agriculture, grazing or other uses. Offshore wind turbines also have a relatively small footprint and are able to use much larger turbines than land-based projects. Rooftop solar deployment, meanwhile, doesn’t require any land.

Of course, to deliver all this clean energy from wind-rich regions in the Midwest and Plains states to major load centers in the East will also require a lot of additional transmission lines. NREL found that total US transmission capacity would have to increase by 1.3 to 2.9 times current levels by 2035. This would require 1,400 to 10,100 miles of new high-capacity lines per year, assuming new construction began in 2026.

But the big news is NREL found that the total amount of land needed by 2035 to achieve our clean power goals with wind, solar and long-distance transmission lines (19,700 sq. mi) would be:

• equivalent to the land area currently occupied by railroads (18,500 sq. mi)
• less than half the area of active oil and gas leases (40,500 sq. mi)
• less than one-third of the area currently needed for ethanol production (59,500 sq. mi), and
• only slightly more than the historically disturbed land area for coal mining (13,100 sq. mi).

Plus, NREL’s main “All Options” scenario projects roughly 250,000 wind turbines in the United States, which is considerably less than the nation’s 1.5 million oil and gas wells.

Environmental and public health benefits

Perhaps most important, though, is the fact that replacing fossil fuels with wind and solar will dramatically reduce the amount of land needed for mining, drilling, transporting, producing and using fossil fuels. Land used for these activities—and for disposing of coal ash and other wastes—often creates significant long-term environmental and public health problems for local communities.

By contrast, the land-use impacts of wind and solar projects tend to be short-term and reversible. As mentioned above, 98 percent of the land needed for a wind farm is available for agriculture, grazing or other productive uses. Co-located solar and agriculture, or “agrivoltaic,” systems can make agriculture more sustainable by improving both energy and food production. Utility-scale solar projects also can be built on previously disturbed and contaminated land that was remediated for reuse, including brownfields, landfills, abandoned mine lands, invasive species-impacted land, gravel pits and quarries, Resource Conservation and Recovery Act and Superfund sites, and retired coal- and natural gas-power plant sites.

And, unlike fossil fuels, electricity generated by wind and solar does not use water or produce any emissions or wastes that can contaminate the air, land or waterways. When wind and solar projects reach the end of their useful lives, they can be removed and the land can be easily restored.

That said, mining some critical minerals for wind turbines, solar panels and batteries can have significant land-use impacts. Stringent policies and safeguards are needed to avoid, minimize and mitigate these impacts. Most of this mining currently occurs in other countries, but the IRA and the infrastructure law both include incentives to source more of these minerals domestically. In addition, several efforts are underway to recycle and reuse wind turbine components, solar panels and batteries instead of disposing them in landfills. (See more on these issues in these recent UCS blogs).

Responsible siting required

Transitioning to a clean energy economy that relies heavily on wind and solar is a big and vitally important undertaking. Minimizing land-use impacts will require responsible siting of wind and solar projects that avoids use of sensitive, or otherwise inappropriate, land and waters.

Fortunately, NREL’s modeling takes much of this into account in its report and related video:

• For wind power, NREL excludes protected land (such as state and national parks, conservation areas, and water bodies), urban areas, and mountainous or difficult terrain. It also considers state and county setbacks as well as height ordinances and excludes land that conflicts with other existing infrastructure, such as buildings, roads, railroads and radar.
• For utility-scale solar, NREL also excludes “prime” or “important” cropland and farmland as designated by the US Department of Agriculture. It also limits potential new solar PV facilities to sites within 12.4 miles of existing transmission in most scenarios.

When these assumptions are taken into consideration, roughly 29 percent of the land in the Lower 48 is available for wind development and 39 percent could be used for solar development under most of NREL’s scenarios.

NREL doesn’t consider changes to land-use patterns, including climate change impacts on land availability. But its implications are clear and heartening: If we develop wind and solar production in a responsible and sustainable way, the land-use demands are manageable and the environmental, public health, and land-use benefits of replacing fossil fuels will be enormous.

A CEPP is an investment program that would incentivize increasing shares of clean electricity by providing financial payments to utilities that procure a certain amount of clean electricity generation each year and charging penalties to utilities that fall short. The overall goal of a well-designed CEPP must be to achieve 80 percent of U.S. electricity generation from low or zero carbon energy sources by 2030. In this way, a CEPP could achieve a similar outcome as a so-called “clean” energy standard (CES), or renewable electricity standards (RES) that have been successfully implemented in multiple states.

A key policy design issue is whether generation from conventional natural gas power plants, as in those without any form of carbon capture and storage, should be eligible to receive partial payments or credits because they produce about half the smokestack CO₂ emissions than coal power plants per unit of electricity. Providing incentives to build new gas power plants and pipelines, and continuing to allow upstream methane leakage when we need to achieve deep reductions in heat-trapping emissions in the next decade and beyond, are bad bets that are incompatible with our climate goals and would lead to major stranded assets and higher costs for consumers.

Here are 5 reasons why subsidizing gas under a CEPP is a bad idea:

1. Increasing gas use is incompatible with decarbonizing the power sector and broader economy

Recent deep decarbonization analyses project that most of the near-term reductions needed to meet economy-wide carbon reduction targets will come from the power sector because of the availability of low-cost alternatives like wind, solar, and energy efficiency to replace coal and gas. 

For example, a new UCS study released in July found that cutting U.S. power sector emissions 80 percent below 2005 levels by 2030 would be a key tool in meeting these broader economy-wide reduction targets. The power sector reductions were achieved by tripling renewable energy generation (primarily new wind and solar) from 20 percent US electricity generation in 2020 to nearly 60 percent in 2030, phasing out coal generation, and reducing gas generation from 40 percent in 2020 to 26 percent in 2030 (see Figure). Getting to 80 percent zero carbon would drive that level of gas generation even lower, and is a worthy target given the slow pace at which other necessary sectoral transitions have been advancing.

Our results are consistent with other recent decarbonization studies by Princeton, University of Maryland, and Evolved Energy Research. A recent UC Berkeley study that analyzed the impacts of a national CES of 80 percent by 2030 also found that gas generation would decline from 40 percent of US electricity generation in 2020 to 20 percent in 2030, and no new gas or other fossil plants would need to be built in the US in the next decade. All of the new generation needed to meet the CES targets and replace gas and coal generation was from wind and solar.

All these studies show we need to drive down gas generation by 2030 to meet power sector and economy-wide emission reduction targets. However, not allowing gas generation to get payments under an 80-percent-by-2030 CEPP does not mean we won’t have gas in the system. Gas could still maintain a market share of approximately 20 percent by 2030 if coal generation is mostly phased out by that time, and a larger share before that.  

2. Gas is not low carbon

The extraction, distribution, and use of natural gas also results in the leakage of methane emissions that pose a major climate risk. Methane is more than 80 times more potent a global warming gas than CO₂ in its first 20 years after release, and approximately 30 times greater over a 100-year period.  

The gas and oil industry is the second largest source of methane emissions in the US after agriculture, representing 30 percent of total emissions in 2019 according to EPA. However, studies by the Environmental Defense Fund (EDF) and hundreds of researchers found that the U.S. oil and gas industry leaks on average 2.3 percent of all the gas it produces, which is at least 60 percent higher than EPA’s estimate of 1.4 percent. A more recent EDF study found even higher leakage rates of 3.7 percent in the Permian Basin in West Texas and Southeastern New Mexico. While these leakage rates may sound small, previous EDF studies show that losses must be kept below 2.7 percent for gas power plants to have lower lifecycle emissions than coal.

Accounting for upstream methane emissions as part of the policy design is vitally important to avoid unintended consequences. If the program accounted for the full lifecycle emissions of gas, then its carbon reduction benefits compared to coal could evaporate entirely.

3. Gas is not clean

Gas has its own set of environmental, public health, and safety issues to contend with. For example, gas power plants release nitrogen oxides (NOx) emissions that cause respiratory problems and react with other substances to produce particulate matter and ozone, which contribute to asthma, heart attacks, and even premature death. To make matters worse, many gas power plants are often located in or near low-income communities and communities of color that are already overburdened with pollution. For example, more than half of all gas power plants in California are concentrated in disadvantaged communities.

Hydraulic fracturing or “fracking” of natural gas, which involves injecting millions of gallons of water and toxic chemicals at high pressure into shale formations, can also result in significant environmental and public health impacts on local communities. This can include air pollution from truck traffic, increases in water use and contamination from toxic chemicals and wastewater leaking into groundwater, and even earthquakes. Methane leakage from pipelines is also a major safety issue that can result in loss of life and property from explosions.

Providing payments for gas generation under a CEPP would only exacerbate these problems.

4. Stranded assets and higher costs for consumers

Providing incentives to build new gas power plants and pipelines under a CEPP when we need to achieve deep reductions in heat-trapping emissions could lead to major stranded assets and higher costs for consumers. In fact, a rush to gas has already occurred with more than 120,000 MW of new gas-fired capacity added between 2008 and 2018, according to data from S&P Global Market Intelligence. This resulted in utility capital expenditures on gas power plants and pipelines rising from just over $60 billion in 2008 to more than $120 billion in 2019.

A new S&P analysis shows that meeting ambitious decarbonization targets such as those included in the Biden Administration’s proposed clean energy standard could result in $34 billion in stranded investments in new gas plants and another $34 billion in stranded coal plant assets.

A 2019 study by RMI found that clean energy portfolios—combinations of renewables, storage, and demand-side management—are projected to be cheaper than 90 percent of proposed gas combined cycle plants and 60 percent of new combustion turbine capacity by 2035. They estimated $90 billion of planned investment in new gas-fired power plants and over $30 billion of planned investment in interstate gas pipelines could be stranded. However, if clean energy replaces the proposed gas plants, they found consumers could save $29 billion.

Recent data from Lawrence Berkeley National Laboratory also highlights the eroding economics of gas power plants, as reflected in the steady decline of gas capacity and the significant increase in solar, wind, and storage capacity in regional transmission interconnection queues over the past 5 years (see Figure). Gas capacity has declined from more than 150 GW in 2015 to 74 GW in 2020, while solar capacity has grown by a factor of nine to 462 GW, wind capacity has more than doubled to 209 GW, and storage capacity has exploded to 200 GW in 2020. While much of the capacity in interconnection queues will not ultimately be built, it clearly illustrates the economic shift away from gas to renewables.

5. Studies showing that partial crediting for gas will accelerate coal retirements are flawed

Some studies have suggested that allowing partial crediting for gas in CES could help accelerate fuel switching from coal to gas that not only reduces CO₂ emissions but also criteria pollutants, resulting in public health benefits.

There is no question that coal has to be rapidly removed from the system. But these studies have several important limitations. First, most of these studies use models that don’t consider upstream methane emissions and other environmental and public health impacts described above from drilling and transporting gas.

Second, most models assume perfectly rational economic decision making and don’t consider various market failures that result in real-world behavior diverging from modeled findings. For example, the practice of “self-committing” allows coal plant owners to operate their plants uneconomically in wholesale markets when lower cost alternatives are available. A 2018 UCS analysis shows that this market distortion is resulting in $1 billion per year in increased costs for consumers across four major US power markets—PJM, MISO, SPP, and ERCOT. Market distortions like this should give policy makers and regulators great pause when considering giving gas-fired power payments under a CEPP.

Many coal plants also have long-term coal contracts that can be a market barrier to retiring and replacing them with gas or other alternatives that aren’t typically captured in models.

Coal-fired and gas-fired power plants and gas pipelines owned by regulated utilities are typically allowed by state PUCs to get cost recovery and a return on investment from ratepayers even if they are more expensive to operate than other alternatives. Most coal and gas plants owned by co-ops or municipal utilities also have approval from their boards to recover these above-market costs from ratepayers.

When these and other factors are considered, providing payments for gas plants under a CEPP could result simply result in windfall profits to the gas industry, and tip the scales away from investing in cleaner low-cost alternatives such as efficiency, renewables, and energy storage.

Coal has to go, but subsidizing gas is the wrong way to achieve it

It’s clear that coal needs to be phased out in the next decade, with proactive investments in a fair transition for coal workers and coal-dependent communities. But incentivizing conventional gas generation under a CEPP is the wrong way to do it. Other policies and regulations will be needed, and would be more effective in driving coal plant retirements–such as implementing stronger EPA regulations, ending the practice of self-commitment, requiring coal plant owners to renegotiate long-term coal contracts, securitization of outstanding coal plant debt, and debt forgiveness for co-op owned coal plants.

Unnecessarily giving natural gas a boost–with all its attendant climate, environmental, health, and economic harms–is not the way to go.

The Solar Energy Industries Association (SEIA) is projecting the US solar industry will lose nearly 114,000  jobs through June, representing 38 percent fewer jobs than the pre-COVID-19 forecast, according to new analysis released today. Instead of growing from a base of 250,000 jobs at the end of 2019 to 302,000 jobs (as projected), SEIA is now projecting total US solar jobs to fall to 188,000 by the end of June. This would negate five years of solar industry job growth.

Source: based on data from SEIA, May 2020.

SEIA is also projecting that solar power construction in the second quarter of 2020—from April to June—will be 1,725 megawatts (MW) less than expected, representing a 35 percent drop from its pre-COVID forecast. These Q2 solar deployment losses are equivalent to the US losing the capability to power 288,000 homes and represents $3.2 billion in lost economic investment, SEIA says.

Some states are being hit much harder than others

A whopping two-thirds of the total solar job losses across the country – a total of 76,439 jobs – are projected to occur in nine states. States experiencing the greatest number of solar job losses include: California (35,687), New York (9,053), New Jersey (5,726), Texas (5,106), Florida (5,617), Massachusetts (4,284), Arizona (4,002), Illinois (3,742) and Pennsylvania (3,222).

The states experiencing the largest job losses as a share of total solar employment include New York, Washington, New Jersey, New Hampshire, Pennsylvania, Connecticut and Idaho. These seven states plus Washington D.C. are projected to lose 60-75 percent of their solar jobs through June, while 21 states will suffer job losses exceeding 40 percent and 36 states will see job losses exceeding 30 percent.

Source: SEIA, May 2020.

Solar is not the only renewable energy source experiencing job losses from COVID-19. The American Wind Energy Association (AWEA) has also estimated that COVID-19 has put 25 gigawatts of US wind projects at risk, representing 35,000 jobs, $35 billion in investment, and $8 billion in tax revenues and land lease payments for state and local economies.

Keeping jobs, keeping workers safe

Jobs in solar, wind and other renewable energy technologies are good, high quality jobs that are worth preserving. The solar industry employs a wide range of occupations including installers, electricians, salespeople, project developers, financiers, and workers that manufacture solar panels and other components.

More than half of total solar jobs in 2019 were in the residential sector. COVID-19 is hitting this solar market segment the hardest because of shelter-in-place orders, social distancing, local permitting delays, and the significant financial uncertainties many families are currently facing. It is also having a disproportionate impact on smaller local solar companies, who are having a much harder time weathering the financial storm than larger companies.

As states start to ease restrictions and gradually re-open, it is essential that all workers, including renewable energy workers, are protected from the virus when they return to their jobs. Unfortunately, the Trump Administration and most states have not put sufficient regulations and standards in place to ensure these vital protections.

Putting the renewable energy industry back to work

With the right policies, the renewable energy industry can play an important role in helping the US economy recover from the recession, putting thousands of Americans safely back to work. Here are three common-sense actions Congress can take:

1. To better protect the workers who have continued to work during the crisis or will soon come back to the job, Congress must require that the Occupational Health and Safety Administration (OSHA) immediately institute a temporary emergency standard that requires employers to ensure their workers are protected from the virus.
2. To stem recent job losses, Congress also should provide immediate relief for the renewable energy industry in the next stimulus bill by extending safe harbor provisions for the production tax credit (PTC) and investment tax credit (ITC) and temporarily providing direct cash payments in lieu of the tax credits until the economy recovers. The IRS recently indicated they will modify the rules for the safe harbor provision “in the near future” in response to an April 23 bi-partisan letter from the chairs and ranking members of the Senate Finance and Energy and Natural Resources Committees to Treasury Secretary Steven Mnuchin. The Senators called for the safe harbor deadlines to be extended by 12 months, from four to five years for projects that began construction in 2016 and 2017. While this news is promising, the IRS has not provided any details on what changes they will make to the rules and current economic stimulus proposals in Congress do not include these provisions.
3. To ensure that the renewable energy industry is able to recover over the longer-term and play a vital role in creating jobs and addressing climate change, UCS and other groups are calling on Congress to extend the ITC and PTC by at least five years and expand it to include stand-alone energy storage. These proposals are also supported by many members of Congress.

Thanks to the leadership of Governor Janet Mills and strong bi-partisan support in the legislature, Maine hit a clean energy grand slam this year, passing several major climate and clean energy bills. In addition to creating new jobs and reducing the state’s reliance on imported oil and natural gas, these laws will put Maine on a pathway to achieve its statewide target of reducing global warming emissions 80 percent below 1990 levels by 2050.

UCS was part of a broad coalition of groups representing businesses, municipalities, and clean energy advocates that supported these bills.

On June 26, Governor Mills signs 3 major climate and clean energy bills into law at state’s largest solar farm in Pittsfield.

Increasing renewable energy to 80% by 2030

LD 1494 doubles Maine’s renewable portfolio standard (RPS) from 40% by 2017 to 80% by 2030 and sets a goal of 100% renewables by 2050. This puts Maine at the top of the batting order, with the highest RPS in the country by 2030. Maine’s RPS surpasses renewable standards of 50% or more by 2030 recently adopted by other leading states (CA, NY, NJ, NM, NV and VT), as shown in the map below.

Sponsored by Sen. Eloise Vitelli (D-Arrowsic), LD 1494 was enacted with strong bi-partisan support, passing the Senate by a unanimous vote of 34-0 and the House 93-48. In addition to testifying in support of the bill, I was a peer reviewer of an analysis of the bill conducted by Synapse Energy Economics and Sustainable Energy Advantage. The study found that the policy is affordable and would deliver the following benefits between 2020 and 2030:

• Install 700 MW of new renewable energy capacity in Maine
• Create 1,900 new jobs in Maine, or about 170 per year.
• Reduce electric sector global warming emissions attributable to Maine by 55 percent.
• Avoid $500,000 per year in health-related damages from burning fossil fuels.
• Result in a modest 1.1% increase in monthly residential and small commercial electricity bills

Maine’s 80% RPS makes the state well-positioned to benefit under a national RPS. The same day Gov. Mills signed LD 1494 into law, Senator Tom Udall (D-NM) introduced a national RPS that would more than double the supply of renewable energy to 50% of US electricity generation by 2035. A UCS analysis showed that a 50% RPS would boost the US economy, benefit consumers, and put the nation on a pathway to decarbonize the power sector by 2050. Senator King co-sponsored the bill because of the potential economic and environmental benefits to Maine of selling renewable energy credits to utilities in other states to help them meet their targets. We hope Senator Collins follows suit, as she has voted in favor of a national RPS at least four times it has come up for a vote in US Senate over the past two decades (see votes in 2002, 2005, and 2015).

Joining the solar revolution

While the RPS is expected to drive significant investments in utility-scale solar projects, LD 1711 is a complementary policy that will allow all Maine’s residents, businesses, and municipalities to become more energy independent by investing in distributed solar projects. Sponsored by Senator Dow (R-Lincoln), it uses competitive markets to deploy at least 400 MW of distributed solar projects of 5 MW or less, with prices that decline over time as more solar is deployed.

By removing arbitrary limits on community solar projects, it provides greater access to clean, affordable power for all renters and homeowners, including provisions that will increase solar investments in low- and median-income households. It will also enable businesses, schools and municipalities to invest in larger solar projects and provides incentives to install projects on landfills and brownfields.

Despite being a northern state, Maine has a much better solar resource than you might expect. According to data from the National Renewable Energy Lab (NREL), a solar PV system installed in Portland will generate slightly more electricity than a system installed in Houston and only 5 percent less than a system installed in Miami.

This bill has a long history going back at least five years. The original proposal was developed by the Maine Public Advocate’s Office following the Maine Value of Solar (VOS) Study in 2014. In addition to participating in the VOS study, I represented UCS in a diverse stakeholder process at the Maine PUC to revise the proposal, which was eventually introduced as legislation. Previous versions of the bill passed the Legislature with bi-partisan support, only to be vetoed by former Governor Paul LePage, who was also a vocal opponent of the RPS.

Governor Mills also signed LD 91 on April 2^nd to eliminate so-called “Gross Metering,” reversing a recent PUC decision that penalized homeowners and business for going solar. When combined with LD 91, LD 1711 will finally unleash solar investment in Maine.

Reducing global warming emissions 80% by 2050

LD 1679 establishes the Maine Climate Council, which is charged with developing action plans to reduce Maine’s global warming emissions 45% below 1990 levels by 2030 and at least 80% by 2050. The bill also promotes clean energy jobs and climate resiliency for local communities as Maine transitions to a low-carbon economy. Sponsored by Senator David Woodsome, a Republican from York, this bill shows that climate and clean energy policy is not a partisan issue in Maine.

Electrifying transportation and buildings

Electrifying vehicles, buildings and industry with clean energy has been identified as a key strategy for replacing fossil fuel use in other sectors and achieving deep cuts in emissions. Maine adopted several policies this legislative session that would help accomplish this, including:

• Increasing the number of EVs plus $5.1 million in rebates EVs and charging stations
• Requiring the PUC to conduct a transportation electrification pilot program
• Establishing a goal of installing 100,000 energy efficient heat pumps in homes and businesses all across Maine. Efficiency Maine currently offers rebates for installing heat pumps for both space heating and water heating.

Maine’s clean energy future looks bright

We applaud Governor Mills and the Maine legislature for passing strong, bi-partisan clean energy legislation that recognizes the urgency of the climate crisis and takes meaningful steps to address it. Maine can finally rejoin the big leagues and regain its all-star status as a clean energy leader that puts the state on a pathway to achieve significant cuts in global warming emissions.

A RES requires electric utilities to gradually increase the amount of renewable energy (wind, solar, geothermal, biomass and hydropower) in their power supplies over time. It uses a market-based approach that stimulates competition among multiple technologies, projects and companies to provide the greatest amount of clean power for the lowest price, and an ongoing incentive to drive down costs. Currently in place in 29 states and D.C., RESs have had a proven track record of success in deploying renewables, creating jobs, and reducing emissions for more than two decades. A national RES would ensure that the entire nation reaps the benefits from accelerating the clean energy transition.

Why a 50% national RES?

A 50% by 2035 RES is feasible and affordable and would help the US meet its climate goals. Over the past decade, the renewable energy share of US electricity sales has grown by nearly 1% per year, on average, according to Energy Information Administration (EIA) data. A 50% RES would more than double that rate through 2035—an aggressive but achievable level consistent with the commitments adopted by leading states and recent analyses showing we can ramp-up to renewables to 80% of US electricity by 2050 and meet mid-century decarbonization goals (see UCS, IPCC, and other studies).

While traditional RES policies establish the overall renewable energy target as a fraction of total retail electricity sales in the future, this proposal takes a novel approach by specifying the amount by which every retail provider in the United States must increase their share of renewable energy each year. This focus on new renewables would help level the playing field between leading clean energy states and states that have underinvested in renewables, regardless of where they are starting from.

Since most existing renewables would not be eligible for federal renewable energy credits (RECs) under the bill, there would be an incentive to build new renewables in-state instead of simply purchasing RECs from existing projects in other states. With the costs of renewables falling dramatically over the past decade, all states now have access to low cost clean energy. The bill would also provide extra credits to install renewable energy projects in economically distressed communities experiencing high levels of pollution or transitioning away from coal.

Key Findings

To understand the impacts of the proposal, we conducted an analysis of a 50% by 2035 RES and found that the policy delivers:

• $374 billion in cumulative new capital investments from 2020-2035
• $34 billion (0.6%) in cumulative net savings on consumer energy bills from 2020-2035
• 46% reduction in power sector CO₂ emissions in 2035

For this analysis, we used the National Renewable Energy Laboratory’s (NREL) Regional Energy Deployment System (ReEDS) model. We compared the RES policy case to a business as usual (BAU) scenario that assumed no new state or federal policies beyond those that existed at the end of May 2019.  See our slide deck and technical appendix for more details on the scenarios and assumptions.

Here are a few more details on what our analysis found:

Energy diversity

A 50% by 2035 national RES would diversify the nation’s electricity mix and reduce the risks of an overreliance on natural gas. Under a BAU scenario with continued low natural gas prices and no new policies, natural gas generation would see significant growth, increasing from 35% of the US electricity mix in 2018 to 58% by 2035 (Figure 1). Most of this new natural gas generation would replace retiring coal plants and a handful of existing nuclear reactors. This level of dependence on natural gas would pose significant risks to consumers and the US economy from potential supply shortages and price volatility.

In contrast, a 50% national RES would roughly double the share of renewables by 2035 compared to BAU, reducing natural gas generation by 38% and nearly phasing out the relatively small amount of remaining coal generation. It would also ensure that any nuclear retirements are replaced primarily with zero-carbon electricity instead of natural gas.

Figure 1. US Electricity Generation under Business as Usual and a 50% by 2035 National RES

Most of the new renewable energy development would come from wind and solar under the 50% RES. Wind capacity would more than double from around 100 gigawatts (GW) today to more than 250 GW by 2035. Solar photovoltaic capacity would increase by a factor of nearly 8 over current levels, reaching 505 GW by 2035, and 332 GW more than BAU.

To help integrate increasing levels of variable wind and solar generation, energy storage capacity would nearly triple to 64 GW by 2035, 32 GW more than BAU. In addition, US transmission capacity would increase by 4% for AC lines and 21% for DC lines, for a combined increase of 4.2 million MW-miles, compared to BAU.

Economic development

The renewable energy deployment under a 50% RES would help make the US a leader in the global clean energy race. It would build on the recent growth in renewable energy jobs in manufacturing, construction, operation, maintenance, and many other industries and would drive significant investment across the economy. A 50% RES would deliver the following economic benefits:

• $374 billion in cumulative new capital investment from 2020-2035; $244 billion more than BAU
• $12 billion in annual operation and maintenance payments in 2035
• $5.6 billion in cumulative property tax payments to local governments from 2020-2035
• $1.4 billion in cumulative wind power land lease payments to rural landowners from 2020-2035

Consumer benefits

Increasing renewable energy use can provide important benefits for consumers. The cost of wind and solar has fallen by more than 70% over the past decade, making renewable energy more affordable for consumers. By increasing competition and diversifying power supplies, renewable energy reduces the demand for fossil fuels, leading to lower and more stable natural gas prices for all consumers.

Under a 50% national RES, power sector natural gas prices are 35% lower than BAU in 2035. The significant reduction in power sector natural gas use would also result in lower costs for homes and businesses that use natural gas for heating, manufacturing, and other purposes.

By 2035, average retail electricity prices are 6.7% higher under the 50% RES compared to BAU, but only 0.2% higher than current levels (Figure 2). However, the reduction in natural gas prices more than offsets the increase in electricity prices, resulting in $34 billion (0.6%) in cumulative net savings on combined consumer natural gas and electricity bills from 2020-2035.

Figure 2. US Average Retail Electricity Prices

A typical household using 600 kWh per month would pay $18 per year in higher electricity bills in 2030, and $51 more in 2035 compared to BAU. However, for the nearly half of U.S. homes that heat with natural gas, typical annual natural gas bills would be $43 lower in 2025, and $94 lower in 2035. Lower natural gas bills for industrial and commercial consumers would also offset slightly higher electricity bills.

A smart climate solution

Increasing renewable energy use is a smart, cost-effective way to reduce carbon dioxide (CO₂) emissions. A national RES is key strategy that would put the US on course to decarbonize the power sector and meet the Paris Climate Agreement.

Under BAU, U.S. power sector CO₂ emissions flatten out and then increase after 2030 due to the increase in natural gas generation. In contrast, CO₂ emissions would be 46% below BAU levels in 2035 under a 50% national RES (Figure 3). Cumulatively, the 50% RES would reduce CO₂ reductions by 4.2 billion metric tons from 2020-2035. These reductions, combined with reductions in other air pollutants, would result in $140 billion in cumulative climate and public health benefits by 2035 based on the U.S. government’s 2016 estimates for the social cost of carbon.

Figure 3. US Power Sector CO2 Emissions

Udall bill offers a pathway to US leadership on clean energy

From our analysis, we can see that Senator Udall’s proposal would put the U.S. on course for decarbonizing the power sector by mid-century. Additional climate and clean energy policies will be needed to meet US climate goals. This includes policies like a carbon price or cap, stronger energy efficiency standards, increased funding for clean energy R&D and infrastructure investments, and incentives for greater electrification of transportation, buildings and industry. Considering the significant economic, consumer, and climate benefits, a strong national RES should be a top priority as Congress considers new policies to transition America to a low-carbon energy future.

When we released our report, my colleague Jeff Deyette described how a proposal backed by FirstEnergy to subsidize its unprofitable nuclear plants in Ohio was deeply flawed and did not meet the conditions recommended in our report. By providing a blatant handout to the nuclear and fossil fuel industries at the expense of renewable energy and energy efficiency, ironically, the latest proposal to create a “Clean Air Program” in Ohio (House Bill 6) is bad for consumers, the economy and the environment.

Here are five reasons why this proposal is flawed and should be rejected:

1. HB 6 doesn’t protect consumers

HB 6 would provide incentives to maintain or build carbon-free or reduced emission resources that meet certain criteria. The state’s Legislative Budget office estimates the new program would cost $306 million per year, collected through a dedicated monthly charge on consumer electricity bills. Monthly costs range from $2.50 for a typical residential customer to $2,500 for large commercial and industrial customers.

HB 6 doesn’t require FirstEnergy Solutions to demonstrate need or limit the amount and duration of the subsidies to protect consumers and avoid windfall profits as recommended in our report. It simply sets the starting price at $9.25/MWh and increases that value annually for inflation.  In 2018, Davis-Besse and Perry generated 18.3 million megawatt-hours of electricity, according to the U.S. Energy Information Administration. This means that FirstEnergy Solutions nuclear plants would receive approximately $170 million per year in subsidies, or 55% of the total. As explained below, the rest of the money would likely go to upgrading Ohio’s existing coal and natural gas plants.

2. HB 6 is a bait and switch tactic to gut Ohio’s clean energy laws

But here’s the rub. HB 6 would effectively gut the state’s renewable energy and energy efficiency standards to pay for the subsidies for Ohio’s existing nuclear, coal and natural gas plants. It would make the standards voluntary by exempting customers from the charges collected from these affordable and successful programs unless they chose to opt-in to the standards. This could result in a net increase in emissions and a net loss of jobs in Ohio over time.

This political hit job is outrageous, but not at all surprising. It is just another attempt in a long series of efforts by clean energy opponents to rollback Ohio’s renewable and efficiency standards over the past five years. When combined with stringent set-back requirements for wind projects that were adopted in 2014, these actions have a had a chilling effect on renewable energy development and explain why renewables only provided a paltry 2.7% of Ohio’s electricity generation in 2018 (see figure below). In contrast, renewables provided 18% of U.S. electricity generation in 2018, and wind power provided more than 15% of electricity generation in 11 states.

The sponsors of HB 6 go one step further and make the false claim that their proposal will save consumers money. While the charges appearing on consumer bills might be less, this ignores the much greater energy bill savings consumers have been realizing through investments in energy efficiency. In addition, the cost of wind and solar has fallen by more than 70 percent over the past decade, making them more affordable for consumers and competitive with natural gas power plants in many parts of the country. It also ignores the energy diversity benefits of renewables and efficiency in providing a hedge against natural gas price volatility. Many Ohio legislators continue to put their heads in the sand and refuse to embrace the new reality that renewables and efficiency are cost-effective for consumers.

Energy efficiency programs are especially important for low-income households. By lowering their energy bills, they have more money to spend on food, health care and other necessities. It also reduces the need for assistance in paying heating bills. Unfortunately, legislators like Energy and Natural Resources Committee Chair Nino Vitale are proposing to provide handouts to large corporations at the expense of easing the energy burden for low-income households, which are also disproportionately affected by harmful pollution from coal and natural gas power plants.

3. HB6 creates a false sense of competition

While renewable energy technologies are technically eligible to compete for funding under HB 6, several criteria would effectively exclude them:

• It excludes any projects that have received tax incentives like the federal production tax credit or investment tax credit, which applies to nearly every renewable energy project.
• Eligible facilities must be larger than 50 MW, which excludes most solar projects, and wind projects have to be between 5 MW and 50 MW, which is smaller than most existing utility scale wind projects in the state.
• Eligible projects must receive compensation through organized wholesale energy markets, which excludes smaller customer-owned projects like rooftop solar photovoltaic systems.

When combined with the rollback to the renewable standard, this absurdly stringent criteria would create too much uncertainty for renewable developers to obtain financing to build new projects in Ohio.

4. HB 6 will increase Ohio’s reliance on natural gas

While HB 6 could temporarily prevent the replacement of Ohio’s nuclear plants with natural gas, gutting the renewables and efficiency standards would undermine the state’s pathway to achieving a truly low-carbon future by locking in more gas generation as coal plants retire.  Over the past decade, natural gas generation has grown from 1.6% of Ohio’s electricity generation to more than 34% in 2018 (see figure). A whopping 40,000 MW of new natural gas capacity was added during this time, mostly to replace retiring coal plants. In contrast, the share of nuclear and renewable generation has only slightly increased by 2-3% each.

Ohio’s Increasing Reliance on Natural Gas for Electricity

While natural gas has lower smokestack emissions than coal, the production and distribution of natural gas releases methane emissions—a much more potent greenhouse gas (GHG) than carbon dioxide. To achieve the deep cuts in emissions that will be needed to limit the worst impacts of climate change, Ohio will need to reduce its reliance on natural gas. Gutting the state’s renewables and efficiency standards would take away the most cost-effective solutions for achieving this outcome.

5. HB 6 includes no safety criteria or transition plans

HB 6 does not require FirstEnergy’s nuclear plants to meet strong safety standards as a condition for receiving subsidies, as recommended in our report. While Davis-Besse and Perry are currently meeting the Nuclear Regulatory Commission’s (NRC) safety standards–as measured by their reactor oversight process (ROP) action matrix quarterly rating system–both plants have had problems with critical back-up systems during the past two years that put them out of compliance.

The nuclear industry has been trying to weaken the ROP for years. For example, the industry has been advocating for combining the first two columns of the action matrix, which would essentially put all nuclear reactors in the top safety category. My colleague Ed Lyman, acting director of the UCS Nuclear Safety Project, is working to stop the NRC from changing the ROP to make it a less meaningful and transparent indicator of plant safety. Our report recommends that policymakers monitor the situation and adjust subsidy policies if the NRC weakens its standards.

HB 6 also does not include any transition plans for affected workers and communities to prepare for the eventual retirement of the nuclear plants. These plans are needed to attract new investment, replace lost jobs and rebuild the tax base.

A better approach

On May 2, House Democrats announced an alternative “Clean Energy Jobs Plan” that would address many of the problems with HB 6. The plan would modify the state’s Alternative Energy Standard (AES) by increasing the contribution from renewable energy from 12.5% by 2027 to 50% by 2050 and fix the onerous set-back requirements that have been a major impediment to large scale wind development. It would expand the AES to maintain a 15% baseline for nuclear power. In addition, it would improve the state’s energy efficiency standards, expand weatherization programs for low-income households, and create new clean energy job training programs.

This proposal is similar to the laws recently passed in Illinois, New York and New Jersey that provided financial support for distressed nuclear plants while simultaneously strengthening renewable energy and energy efficiency standards. While our report shows that the subsidies for some of these nuclear plants may have been too generous, these policies have prevented plants from closing and resulted in a wave of new investment in wind, solar, and efficiency projects.

With more than 112,000 clean energy jobs in 2018, Ohio ranks third in the Midwest and eighth in the country. Ohio added nearly 5,000 new clean energy jobs in 2018.  While most of the clean energy jobs are in the energy efficiency industry, Ohio is also a leading manufacturer of components for the wind and solar industries.

To capitalize on these rapidly growing global industries, lawmakers in Ohio should reject HB 6 and move forward with a real clean air program that ramps-up investments in renewables and efficiency and achieves the deep cuts in emissions that are needed to limit the worst impacts of climate change.

Unfortunately, some of the media coverage and statements by the nuclear industry and other groups have mischaracterized our report and our past work. Here are seven points to correct the record:

1. The report does not promote new nuclear power plant construction.

Our analysis is focused on the economic viability of existing nuclear power plants in the United States through 2035. The cost of keeping existing plants operating is considerably less than building new ones. While new nuclear plants could be built under a national carbon price or low-carbon electricity standard, our modeling shows they are too expensive compared to new wind and solar projects, energy efficiency programs, and natural gas plants with carbon capture and storage.

The only new nuclear reactors included in our analysis are the two currently under construction at the Vogtle plant in Georgia. Their cost has ballooned to more than $27 billion, which is double the estimate approved by regulators in 2008, and the project is more than five years behind schedule. This 2012 UCS analysis shows that building the two new Vogtle reactors would be more expensive than other alternatives. And the Vogtle reactors’ cost has escalated significantly over the past six years, while the cost for wind and solar has fallen dramatically.

This isn’t the first time UCS has shined a spotlight on the high costs of building new nuclear reactors. This 2016 UCS power sector deep decarbonization study found that nearly all nuclear and coal plants in the United States would be replaced by low-carbon technologies by 2050 under every scenario, except our “optimistic nuclear case.”  A blog I wrote in 2013 explains why calls by some climate scientists to build new nuclear plants are misguided.

2. The report does not advocate for subsidies for any specific nuclear plants.

The report emphasizes that a price on carbon or a low-carbon electricity standard (LCES) would be the best options for internalizing the costs of climate change in the price of burning fossil fuels and providing a level playing field for all low-carbon technologies. As explained by UCS President Ken Kimmell in his recent blog, “the report does not argue for subsidies to any specific plants. That case will have to be made in state-specific forums. Should states decide to support nuclear power plant subsidies, our report calls for them to be temporary and subject to periodic reassessment. Companies seeking subsidies must open their books and allow the public and regulators to make sure that the subsidies are needed and cost-effective, and that the same level of carbon free power cannot be provided during the relevant time period with less costly options.” Any subsidies also must be part of a broader strategy to reduce carbon emissions that increases investments in renewables and efficiency.

Finally, our report makes clear that UCS would never support financial assistance that is also tied to subsidizing fossil-based energy sources, such as Trump administration proposals to bail out coal and nuclear plants based on spurious grid-reliability and national-security grounds.

3. Existing nuclear plants must also meet strong safety standards to be eligible for support.

Since the 1970s, UCS has been a leading nuclear safety watchdog. The new UCS report recommends that nuclear reactors must meet or exceed the highest safety standards under Nuclear Regulatory Commission’s (NRC) Reactor Oversight Process to be eligible for any policy or financial support. If the NRC weakens these standards, as proposed by the nuclear industry, UCS could no longer support this recommendation. At the same time, UCS will continue to push for better enforcement of existing regulations, the expedited transfer of nuclear waste from overcrowded cooling pools to safer dry cask storage, strengthened reactor security requirements, and higher safety standards for new plants. We also consider the NRC safety standards to be a floor, not a ceiling. States could encourage plant owners to make other safety improvements that go beyond current NRC standards.

4. Not every currently operating nuclear plant should stay open.

The report highlights examples where it might make sense to shut down existing nuclear plants that are saddled with major, reoccurring safety issues such as the Pilgrim plant in Massachusetts that Entergy is closing next year and the Davis-Besse plant in Ohio that FirstEnergy is threatening to close in 2020 if it doesn’t receive subsidies. Other examples include Indian Point, due to its proximity to New York City, and Diablo Canyon, which is located near earthquake fault lines in California.

It also might make sense to shut down plants with high operating costs or ones that need to make major new capital investments to continue operating safely. Examples cited in the report include Crystal River in Florida and San Onofre in California, which were retired in 2013 following failed steam generator replacements. Fort Calhoun in Nebraska shut down in 2016 primarily for economic reasons following several years of extended outages and flood damage. Chris Crane, CEO of Exelon, agrees that some high-cost plants should probably close: “I will be the first one to tell you that some of the nuclear plants are small, uneconomic and they won’t make it and they probably should not make it,” he said. “Let’s not save every one.”

5. Not every nuclear plant that retires early will be replaced with fossil fuels.

The report acknowledges that with sufficient planning and strong climate and clean energy policies, some existing nuclear plants can be replaced with renewables, energy efficiency, or other low- carbon technologies. For example, California passed legislation in September that commits the state to replace Diablo Canyon with zero-carbon energy sources by 2025. And states experiencing rapid wind and solar power deployment such as Iowa, Nebraska, Kansas, and Texas could potentially replace their nuclear plants with low-carbon energy sources over a reasonable period of time. However, a significant portion of the electricity in most of those states is still generated by coal and natural gas. Replacing those fuels with renewables and efficiency would result in much greater emissions reductions than replacing nuclear plants, another low-carbon source of electricity.

6. UCS has long recognized the role of existing nuclear plants in reducing carbon

UCS has long supported keeping existing nuclear reactors that meet high safety standards operating to combat climate change. In 2004, the director of our energy program at the time, Alan Nogee, stated: “We cannot phase out current nuclear generation quickly, especially without [a] significant increase in carbon emissions.” Five years later, we released our “Climate 2030 Blueprint,” which assumed the fleet of more than 100 US reactors would continue to operate through 2030 and beyond. You will find in the report’s executive summary: “Hydropower and nuclear power continue to play important roles, generating slightly more carbon-free electricity in 2030 than they do today.”

US Electricity Generation under the UCS Climate 2030 Blueprint

Two years ago we posted a  “Nuclear Power and Global Warming” page on our website, highlighting the need for all low-carbon technologies, including nuclear power, to limit the worst consequences of climate change. The web page also warns that replacing existing nuclear power plants with natural gas plants would increase carbon emissions.

In 2016, UCS was involved in negotiations in Illinois to keep two uneconomic nuclear plants running, while strengthening the state’s renewable energy and energy efficiency standards. We posted the following blogs on the topic: “A Huge Success in Illinois: Future Energy Jobs Bill Signed Into Law,” “The Future Energy Jobs Bill: Promise, Pitfalls, and Opportunities for Clean Energy in Illinois,” and “New Analysis Shows Fixing Illinois Clean Energy Policies Is Essential to Any ‘Next Generation Energy Plan.’”

7. UCS has long supported a low carbon electricity standard (LCES), but not at the expense of renewable electricity standards (RES).

Since at least 2011, UCS has engaged in constructive dialogues and provided support for LCES proposals. See here, here, here, and here. More recently, UCS advocated for the 100 percent zero-emission electricity standard in California that was signed into law in September.

While an LCES could be effective at preserving existing nuclear generation and increasing the deployment of renewable energy and other low-carbon technologies, our position has remained consistent (including in our new report) in that we do not recommend replacing state RESs with broader LCESs. Renewable standards have been effective at reducing emissions, driving down the cost of wind and solar, and creating jobs and other economic benefits for states and in rural communities. They have also been affordable for consumers. Including existing nuclear power plants in state renewable standards could significantly undermine the development of new renewables and all the benefits that go along with them.

We recommend including existing nuclear in a separate tier of an LCES, as New York state has done, to limit costs to ratepayers and avoid market-power issues due to limited competition among a small number of large plants and owners. New York also has combined an LCES with a zero-emission credit program to provide financial support only to existing nuclear plants that need it, adjusting support as market conditions change. New technologies would be eligible to compete in the existing tier to help ensure that the most cost-effective, low-carbon energy sources replace any retiring nuclear plants. Illinois and New Jersey also strengthened their renewable standards while providing separate financial support for distressed nuclear plants.

And finally, despite reporting to the contrary, UCS has not changed its position on nuclear power. Has UCS advocated vigorously for policies to increase the deployment of renewable energy to address climate change? Absolutely. Have we been a longstanding watchdog for nuclear power safety? You bet. Do we now believe the Nuclear Regulatory Commission (NRC) is an effective watchdog or that nuclear power safety concerns are overblown? Emphatically no.

But UCS has long recognized that the current nuclear fleet is a significant source of low-carbon power and that nuclear plants should not retire precipitously without carbon-free replacements. As cited above, my former colleague Alan Nogee tweeted a slide from 2004 showing that UCS grappled with just this point more than a decade ago:

The uneconomic plants include Xcel’s Monticello and Prairie Island nuclear power plants, which provided 23 percent of Minnesota’s electricity generation in 2017 and about half of the state’s low carbon electricity. A key reason why these plants appear to be uneconomic compared to cheaper alternatives is because current market prices do not include the costs and damages inflicted on the climate and society from burning fossil fuels.

Without strong policies such as a meaningful economy-wide cap or price on carbon emissions, the study found that natural gas and coal would largely replace the lost generation from closing at-risk nuclear plants before their operating licenses expire, resulting in an increase in US power sector carbon emissions over the next two decades. In stark contrast, the Intergovernmental Panel on Climate Change (IPCC) released a sobering report last month showing that to limit global average temperature increases to 1.5^o Celsius (2.7^o Fahrenheit) and avoid some of the worst impacts of climate change, the US and other countries will need to achieve net zero global warming emissions by 2050, with half of those reductions coming by 2030.

US nuclear power plants at risk of early closure or slated for early retirement

More than one-third of existing plants, representing 22 percent of US nuclear capacity, are unprofitable or scheduled to close.

What does this mean for Minnesota?

The UCS study analyzes the economic viability of the nation’s nuclear plants based on how much revenue they could earn from selling electricity into the wholesale market and from providing capacity to the electricity system during times of peak demand compared to how much it costs to operate them. The study’s methodology and results are consistent with several recent studies by MIT, Bloomberg and others, that also showed Monticello and Prairie Island are more expensive than cheaper energy alternatives available in market.

The risk of closing of these plants early is lower than nuclear plants owned by “merchant” generators that sell their power in states and regions with competitive markets. This is because regulated utilities like Xcel are typically allowed to recover the costs of operating their plants from customers, along with a return on investment, subject to approval from state Public Utilities Commissions (PUCs).

While the risk might be lower, regulated utilities are not completely immune from the market pressures of lower cost alternatives. For example, the fact that regulated utilities have also historically received cost recovery for coal plants hasn’t stopped Xcel and other regulated utilities across the country from retiring and replacing them with lower cost alternatives such as natural gas, wind, solar and efficiency. And like many utilities that needed to make investments in pollution control equipment to reduce public health impacts from coal plants, Xcel and many other utilities are planning on making major capital investments to upgrade their aging nuclear plants.

Earlier this year, the Minnesota legislature rejected a bill that would have pre-approved $1.4 billion in new upgrades over the next 17 years to keep Xcel’s nuclear plants running until their operating licenses expire. UCS and many Minnesota groups opposed this legislation because it would have circumvented the state PUC, which provides important oversight to make sure any new utility investments are prudent for ratepayers compared to other alternatives. Retaining the PUC’s authority to oversee these investments is especially important given the over $400 million in cost overruns and delays Xcel experienced when they made the last major upgrades to Monticello in 2013.

A meaningful value for low-carbon generation makes Xcel’s nuclear plants profitable

Today, the price of coal and natural gas does not reflect the costs inflicted on society from climate change that results from burning fossil fuels. The UCS report recommends national or state policies that put a cap or price on carbon emissions as the best approach to address this market failure and level the playing field for all low carbon technologies.

Our analysis shows that a national price on carbon dioxide (CO₂) emissions that starts at $25 per metric ton in 2020 and increases 5 percent per year would be enough to make Monticello, Prairie Island, and all of the other uneconomic nuclear plants in the country profitable. While Minnesota currently does not have a carbon price, the Minnesota PUC has required Xcel and other utilities to include a range of CO₂ prices in their Integrated Resource Plan (IRP) modeling since 2008. Working with other clean energy groups in Minnesota, UCS played an important role in advocating for this.

The PUC updated these values earlier this year, requiring utilities to model scenarios that include a range of $5-$25 per ton of CO₂ starting in 2025 to reflect the likelihood of future CO₂ regulatory costs. The PUC also requires utilities to include in their modeling a range of environmental externality costs of $8.44-$39.76 per ton of CO₂ in 2017, increasing to $15.20-$69.48 per ton of CO₂ in 2050, based on the federal social cost of carbon.

Xcel is counting on nuclear to meet its 2030 carbon-free vision

Xcel is in the process of conducting modeling for its next IRP to determine the mix of electric generating technologies they will invest in between 2019 and 2034 to meet electricity demand, while maintaining reliability and minimizing costs to customers. The plan is due February 1, 2019, but Xcel recently requested a five-month extension to July 1.

Xcel is counting on running both of its nuclear plants until their 60-year operating licenses expire (in 2030 for Monticello, and in 2033 and 2034 for the two reactors at Prairie Island) to meet the utility’s goal of 85 percent carbon-free electricity by 2030 across its system in the Upper Midwest. To achieve this goal, Xcel is retiring and replacing most of their coal plants in Minnesota with energy efficiency, major new investments in wind and solar power that would increase renewables to 60 percent of their electricity sales by 2030, and a new natural gas plant that was recently approved by the legislature. At the same time, Xcel is projecting an increase in electrification of vehicles and buildings that will result in greater electricity demand and the need for more low carbon generation.

Source: Xcel CEO Ben Fowke presentation to Minnesota PUC, October 17, 2017

Replacing an additional 1,770 MW of capacity from Xcel’s nuclear plants in the next decade would be challenging to do, without increasing natural gas use and carbon emissions. In addition to making it difficult for Xcel to achieve its emission reduction targets, an overreliance on natural gas would pose economic risks to consumers. But with more time and continued cost reductions for clean energy, it’s more likely that Xcel could replace its nuclear plants with renewables, efficiency and other low carbon technologies when their licenses expire.

Xcel is required to consider these tradeoffs as part of its IRP. The IRP process at the PUC is the appropriate venue to evaluate these complicated tradeoffs—including whether the $1.4 billion Xcel wants to invest in upgrades for its nuclear plants is the best way to spend ratepayer money compared to other low carbon alternatives. The legislature is not the place to address these complex issues.

Time for the next generation of climate and clean energy policies in Minnesota 

It has been more than a decade since Minnesota has passed major climate and clean energy legislation. The Next Generation Energy Act of 2007 required Minnesota utilities to meet a renewable electricity standard of 25 percent by 2025 (and 30 percent for Xcel), achieve energy efficiency savings targets to reduce electricity and natural gas usage by 1.5 percent per year, and adopt a statewide goal of reducing global warming emissions at least 30 percent below 2005 levels by 2025 and at least 80 percent by 2050.

As I have mentioned in previous blogs, these policies have made Xcel and Minnesota national clean energy leaders. But since 2007, six states have adopted higher renewable standards of 50 percent or more by 2030 and other leading states have adopted stronger energy efficiency standards that reduce electricity use by 2-3 percent per year. In addition, the cost of deploying wind, solar, and battery storage has fallen dramatically over the past decade, while many energy efficient technologies, such as LED lighting, have also improved.

Despite progress, Minnesota still has a long way to go to meet its statewide emission reduction targets. Reducing emissions 80 percent by 2050 will likely require increased electrification of vehicles and buildings with zero carbon electricity sources to achieve reductions in other sectors. Stronger climate and clean energy policies will be needed to meet these targets and to ensure that when Xcel’s nuclear plants are eventually retired, they are replaced with low carbon technologies.

Originally enacted as part of the Energy Policy Act of 1992, Congress has extended the Production Tax Credit (PTC) seven times and has allowed it to expire on six occasions. This “on-again/off-again” status resulted in a boom-bust cycle of development in the wind industry. In the years following expiration, installations dropped between 76 and 93 percent, with corresponding job losses. Congress has also extended the Investment Tax Credit (ITC) for solar several times.

Finally, after many years of this policy uncertainty, Congress passed a five-year extension and phase-down of the PTC and the ITC for wind and solar in December 2015. The legislation also removed the longstanding US oil export ban, as part of a compromise deal with the oil industry.

Unfortunately, the Senate and House tax bills would renege on this deal and change the rules midstream, resulting in major job losses across the US renewable energy industry. They would also jeopardize tens of billions in investments in renewable energy projects and manufacturing facilities in rural communities across America—many of which are in districts and states held by Republicans and that voted for President Trump.

Senate tax bill undermines renewable energy financing

The renewable energy industry initially praised an earlier version of the Senate tax bill, which honored the 2015 deal and did not make any direct changes to the PTC and ITC. However, the Senate made two last-minute changes to the bill to fill revenue gaps and build support from key Republicans that were concerned about the deficit that would have a significant impact on renewable energy projects.

Alternative Minimum Tax (AMT): One of these last-minute changes was to restore the AMT to fill a $40 billion revenue gap. The proposal in both the Senate and House tax bills to reduce the corporate tax rate to 20 percent would likely move most US corporations from the regular corporate income tax rate to the AMT (which is also set at 20 percent on a broader tax base), according to tax experts.

However, not all tax credits count toward the AMT and depreciation must be calculated at a slower rate. While the ITC for solar projects can count toward the AMT, the PTC for wind projects (and geothermal, biomass, landfill gas and incremental hydro projects) can only count for the first 4 years out of the 10-year window that projects are eligible to receive the tax credits. Not only would this jeopardize investment in new projects, it would have a retroactive impact on existing projects placed in service after 2007 that are still receiving tax credits under the PTC.

Base-Erosion Anti-Abuse Tax (BEAT): The Senate also made a last-minute change to the BEAT provision that could greatly reduce tax equity financing for renewable energy projects. BEAT would impose a tax on large corporations that make cross-border payments by requiring them to add those payments to their taxable income. This amount is then multiplied by 10 percent to determine what they owe to the government (except for banks and security dealers, which the Senate raised to 11 percent). These corporations must also calculate their regular tax liability minus any tax credits they receive, including the PTC and the ITC. If their adjusted tax liability is less than the fraction of their taxable income with the cross-border payments, the company would have to pay the difference to the IRS as a tax.

The more tax credits a company has, the more a company is likely to pay, making banks and other large tax equity investors reluctant to finance renewable energy projects. And like the AMT, the BEAT provision would not only impact financing for new projects but could have a retroactive effect on most existing projects that received tax equity financing.

Bloomberg New Energy Finance (BNEF) claims that the Senate bill could threaten $12 billion in annual tax equity financing in 2017, up from $7.3 billion in 2013 (see Figure). They estimate that tax equity financing accounted for 21 percent of the $58.5 billion in total US renewable energy investment in 2016.

The Senate tax bill would have a big impact on companies like JPMorgan, Bank of America, GE, US Bank, and Citigroup that led tax equity financing in 2016 for both wind and solar projects, as shown in this BNEF chart.

The BEAT provision would also hurt other energy sources that currently receive tax credits such as refined coal facilities placed in service by December 2011. The coal industry is also speaking out against the AMT, which Bob Murray claims will cost his company $50-60 million in increased taxes and eliminate 65,000 jobs.

House bill puts 60,000 wind industry jobs and $50 billion in new investment at risk

While the House bill does not include the AMT or BEAT provisions, it makes several direct changes to the PTC and ITC that would undermine investments in new wind and solar projects and have a retroactive impact on existing projects. These changes include:

• Eliminating the inflation adjustment for the PTC, reducing its value by 38 percent from 2.4 c/kWh under current law to 1.5 c/kWh.
• Changing the commence construction provision, dropping safe harbor provision, and requiring projects to have “continuous construction” to be eligible, which would greatly accelerate the PTC phase-down schedule. When combined with the change to the inflation adjustment, AWEA estimates these two provisions could reduce the value of the PTC by more than half.
• Allowing the permanent 10 percent solar ITC to sunset in 2027.
• Extending the tax credits to “orphan” technologies like geothermal, biopower, landfill gas, and incremental hydro that were largely left out of the 2015 deal to extend the tax credits for wind and solar for 5 years. This is the only positive change in the House bill.

The House bill would cut new wind development by more than half by 2020, according to both Bloomberg and Goldman Sachs. AWEA estimates that the House bill would put 30,000 MW of new wind projects that are under development in the US worth $50 billion of new private investment at risk, along with 60,000 jobs, as shown in this map.

Source: AWEA, Protecting American wind workers during tax reform.

Making renewable energy a priority in conference committee

The provisions in the House bill that renege on Congress’ 2015 compromise deal with the oil industry and drastically cut the value of the PTC are completely unacceptable and should be dropped. The AMT and BEAT provisions in the Senate bill should either be dropped (they are not included in the House bill) or renewable energy tax credits should be excluded—similar to how R&D tax credits are currently excluded from the BEAT provision.

House and Senate conferees were named last week. They will meet over the next two weeks to resolve key differences, with the goal of delivering a final bill to President Trump by the end of the year.

It is an ominous sign that Senator Grassley (R-IA), a senior member of the Senate Finance Committee, was left off the conference committee. As the father of the PTC, who represents a state that ranks second in installed wind capacity, he has been outspoken about honoring the 2015 deal and working to fix the problems in the Senate and House tax bills. “The wind energy production tax credit is already being phased out under a compromise brokered in 2015. It shouldn’t be re-opened,” Grassley said.

Pro-renewables Senators like Grassley and Susan Collins (R-ME) will have a tough vote to make on the Senate floor if these damaging provisions are not addressed in conference. Maine, for example, has over 900 MW of existing wind capacity and nearly 300 MW of new solar and wind under development that is potentially at risk.

But there are conferees who represent states with large renewable energy industries, and they are in unique position to make the changes necessary to keep that clean energy momentum going.

• Conferees like Senator Thune and Representative Noem from South Dakota, where a wind turbine blade manufacturer from Aberdeen just announced they will be closing and laying off over 400 people, citing the federal tax bills as one of reasons for this decision. “It’s apparent that the new tax bill will cause some economic disruption and this is one of them,” according to Aberdeen Mayor Mike Levsen. “It’s what happens when government policies turn against industries. It discourages investment.” South Dakota also has 960 MW of wind projects currently under development, representing $1.6 billion in new investment, that is at risk.
• Senator Murkowski (R-AK) has also said that fixing the BEAT and AMT provisions in the Senate bill will be “clear priorities” for lawmakers in conference
• Senator Portman (R-OH) is from a state with a strong renewable energy supply chain, including 5,831 solar jobs at 189 companies and more than 2,000 jobs and 61 manufacturing facilities in the wind industry. Ohio also has 560 MW of new wind projects under development and $900 million in new investment that is at risk.
• Other conferees from leading renewable energy states such as Texas, California, Illinois, Washington and Oregon would also experience significant job losses.

The US renewable energy industry has a proven track record of creating new jobs and making new investments in states and rural areas across America. Federal tax reform should encourage rather than discourage US investment in this rapidly growing global industry.

Make sure your members of congress know clean energy is important to you. Tell them to fix the AMT and BEAT provisions, and to leave the renewable energy tax credits alone.

Do you think we’re going to learn anything new in 60 days that these experts and real-world experience haven’t already answered over the past decade?

Secretary Perry’s biased and unnecessary study is just yet another blatant attempt by the Trump Administration to prop up the ailing coal industry and undermine important renewable energy policies that are providing clean, reliable, and affordable power to consumers. Renewable energy business associations, Senate Democrats, and even prominent Senate Republican Chuck Grassley from Iowa have raised similar concerns about the study’s motivation and credibility.

What does a credible study look like?

Typically, important tax-payer funded government studies are done in an open and transparent manner over a period of several months or years, with input and review from outside experts, key stakeholders, and the public. This approach helps balance varying viewpoints, avoid political interference, and ensure objectivity.

Here are two examples of DOE studies on renewable energy and reliability that were done the right way:

• NREL’s 2012 Renewable Electricity Futures Study, a massive 850-page study developed by more than 100 experts from 35 diverse organizations and peer-reviewed by more than 140 experts. The study found that with a more flexible electricity system, grid operators would be able to balance electricity supply and demand and maintain reliability in every hour of the year with renewable energy providing 80 percent of US electricity by 2050.
• DOE’s 2015 Wind Vision Study, a comprehensive analysis of the costs and benefits of producing 20 percent of US electricity from wind power by 2030 and 35 percent by 2050. More than 250 experts and 50 organizations—representing the wind industry, utilities, grid operators, non-governmental organizations, and four DOE national labs—contributed to the report.

Perry’s study doesn’t meet these standards

In addition to the absurd 60-day deadline, the study is being conducted behind closed doors with no input or review from outside experts or the public. And the research questions (if you want to call them that) have either been answered already or are clearly biased against renewable energy.

To make matters worse, the study is being directed by individuals who have been openly hostile to renewable energy and supported by the fossil fuel industry. Travis Fisher and his boss Daniel Simmons, appointed by President Trump to oversee DOE’s Office of Energy Efficiency and Renewable Energy (which they once recommended eliminating), are former employees of the Institute for Energy Research (IER), and its advocacy arm, the American Energy Alliance (AEA), which actively supports rolling back state and federal climate and clean energy policies. (For more details, see these blogs by Elliott Negin and Dave Anderson.)

In 2015, Fisher wrote a report for IER calling clean energy policies a greater threat to reliability than extreme weather, cyber attacks, or terrorism. To address this so-called threat, Fisher recommended repealing federal renewable energy tax credits, state renewable energy standards, state net metering policies, and the EPA’s Clean Power Plan and Mercury and Air Toxics Standards.

It’s no secret that the Trump Administration is targeting many of these policies. Perry also made a highly controversial comment at a Bloomberg New Energy Finance Conference in late April saying they were having “very classified” conversations about DOE potentially overturning state and local renewable policies in the name of national security.

What we would expect to see in a rigorous study

If Perry’s grid study is done right, here are 7 important things we would expect it to show based on current trends and recent credible studies:

1. Renewables are diversifying the electricity mix (see pie charts), making the grid more reliable and resilient. Regional grid operators and utilities are already integrating high levels of wind and solar of 50 to 60 percent or more of total electricity demand in some parts of the country, including Texas, while maintaining and even improving reliability.
2. The national labs, regional grid operators, utilities and others have completed dozens of studies showing that the US can achieve even higher levels of renewable energy in the future, while producing reliable, affordable, and cleaner electricity, as explained in this letter signed by UCS.
3. Baseload power plants pose their own reliability challenges because of their large size, limited flexibility, and vulnerability to extreme weather events such as the Polar Vortex, extreme heat and drought impacts on cooling water, and storm surge from Hurricanes. This 2013 DOE report highlights numerous climate and extreme weather-related risks to our energy infrastructure.
4. There is widespread agreement from energy experts that low natural gas prices and flat electricity demand are the main causes of recent coal and nuclear retirements, not renewable energy, as highlighted in new report by the Analysis Group.
5. Fossil fuels and nuclear power have received far more subsidies than renewable energy historically, and are part of the permanent tax code while tax credits for renewables are set to phase out in a few years.
6. The costs of utility scale wind and solar have fallen by more than two-thirds since 2009, which has made renewable energy more affordable to consumers.
7. Federal tax credits and state renewable standards have been key drivers for the cost reductions and recent deployment of wind and solar that are creating new jobs and other economic benefits across America, particularly in states and rural areas that voted for President Trump.

Renewable energy and natural gas are diversifying the US electricity mix

Source: Energy Information Administration

The study, not renewables, is a waste of taxpayer money

If Perry’s study reaches different conclusions, or cherry picks information that supports the Trump Administration’s predetermined conclusions, it should raise a major red flag.  Perhaps Republican Senator Chuck Grassley from Iowa (which gets 36 percent of its electricity from wind) said it best in his letter to Perry: “I’m concerned that a hastily developed study, which appears to pre-determine that variable, renewable resources such as wind have undermined grid reliability, will not be viewed as credible, relevant or worthy of valuable taxpayer resources.”

Numerous cost-effective climate solutions are available that can create jobs and reduce emissions at the same time to help meet the Paris Agreement. In fact, solutions like improving the energy efficiency of our homes, offices, factories and cars, and investing in solar and wind power can take us most of the way there and actually save consumers money.

When you include the public health and environmental benefits of clean energy, the savings and economic benefits are even larger.

Wind power is working for America

For wind power in particular, recent data from the American Wind Energy Association’s (AWEA) 2016 Annual Market Report show how wind is creating high quality jobs and important economic benefits to rural areas, while reducing emissions at the same time.

US wind capacity has more than doubled since 2010, accounting for nearly one-third of all new electric generating capacity since 2007. Wind power surpassed hydropower in 2016 to become the number one source of renewable electric generating capacity in the country. The wind industry installed more than 8,200 megawatts (MW) of new capacity in 2016, bringing the total US installed capacity to 82,000 MW. Wind power generated 5.5 percent of total US electricity generation in 2016, the equivalent of meeting the entire electricity needs of 24 million average American homes.

Wind industry jobs are growing fast. The US wind industry added nearly 15,000 new jobs in 2016, reaching a total of 102,500 full-time equivalent jobs in all 50 states, up from 50,500 jobs in 2013. Wind power technician is the fastest growing job in the US, according to the Bureau of Labor Statistics. Texas, the national leader in installed wind capacity, also has the most wind-related jobs with more than 22,000, followed by Iowa, Oklahoma, Colorado, and Kansas, each having 5,000 to 9,000 wind jobs (see map).

Source: AWEA annual market report, year-ending 2016.

Domestic wind manufacturing is expanding. Wind power supports 25,000 US manufacturing jobs at more than 500 facilities located in 43 states. US wind manufacturing increased 17 percent in 2016, with 3 new factories opening and 5 existing factories expanding production. Ohio is the leading state for wind manufacturing with more than 60 facilities, followed by Texas (40), Illinois (35), North Carolina (27), Michigan, Pennsylvania and Wisconsin (26 each).

While manufacturing jobs are concentrated in the Rust Belt, Colorado, Iowa, and California are also national leaders manufacturing major wind turbine components, and the Southeast is a major wind manufacturing hub with more than 100 factories. US facilities produced 50-85 percent of the major wind turbine components installed in the United States in 2015, up from 20 percent in 2007, according to Lawrence Berkeley National Lab (LBNL).

Investing in rural communities. The wind industry invested $14.1 billion in the US economy in 2016, and $143 billion over the past decade, with most of this flowing to rural areas where the wind projects are located. Wind energy also provided an estimated $245 million annually in lease payments to farmers, ranchers and other landowners in 2016, with more than $175 million occurring in low-income counties. AWEA estimates that 71 percent of all wind projects installed through 2016 are located in low-income rural counties.

And now for the kicker…

Wind power is providing major economic benefits to President Trump’s base. AWEA estimates that 88 percent of the wind power added in 2016 was built in states that voted for President Trump. In addition, 86 percent of total installed wind capacity in the US and 60 percent of wind-related manufacturing facilities are located in Republican districts.

Source: AWEA annual market report, year-ending 2016.

Wind power is affordable for consumers. The cost of wind power has fallen 66 percent since 2009, making renewable energy more affordable to utilities and consumers. A 2016 NREL and LBNL analysis quantifying the benefits of increasing renewable energy use to meet existing state renewable standards found that the health and environmental benefits from reducing carbon emissions and other air pollutants were about three times higher than the cost of the production tax credit (PTC).

Wind power is reducing emissions: AWEA estimates that existing wind projects avoided nearly 159 million metric tons of carbon dioxide (CO₂) emissions in 2016, equivalent to 9 percent of total power sector emissions, as well as 393 pounds of SO₂ and 243 million pounds of NOx emissions.

More wind development, jobs, and emission reductions are on the way

And there’s lots more to come. Wind development will continue over the next few years due to the recent 5-year extension of the federal tax credits, state renewable electricity standards, and continued cost reductions. Studies by NREL, EIA, and UCS project that the tax credit extensions will drive 29,000 to 59,000 MW of additional wind capacity in the US by 2020.

Similarly, a study by Navigant Consulting projected 35,000 MW of new wind capacity will be installed in the US between 2017 and 2020, increasing total wind-related jobs to 248,000 by 2020 and injecting $85 billion into the US economy. They also found that each wind turbine creates 44 years of full-time employment over its lifetime.

When combined with additional deployment of solar, NREL found that the federal tax credit extension would result in a cumulative net reduction of 540 to 1,420 million metric tons (MMT) of CO₂ emissions between 2016 and 2030, depending on projected natural gas prices.

Studies by EPA and UCS also show that the Clean Power Plan (CPP)—a key policy for achieving the US Paris commitments–would continue to drive wind and solar development and emission reductions through 2030, with the public health and environmental benefits greatly exceeding the costs.

Backing away from Paris and the CPP could actually hurt the US economy

All these amazing facts show that President Trump is wrong to ignore the economic benefits of wind and other clean energy options for the US, and that’s a real shame.

Market forces and continued cost reductions will drive more clean energy development in the US in the near-term. However, countries like China and India are also making significant investments in renewable energy as a key strategy for reducing emissions under the Paris Agreement.

For America to maintain its leadership position in the global clean energy race, we need strong long-term climate and clean energy policies like the Paris Agreement and the Clean Power Plan. Our country will be stronger for it, not weaker.

Trump has also supported the development of so-called “clean coal” as a way to revive the industry. A key component to making coal cleaner is the process of capturing the carbon dioxide (CO₂) emissions from burning coal in power plants or industrial facilities, and transporting and storing the CO₂ underground so that it cannot add the to atmospheric build-up of carbon emissions that is driving climate change (a process otherwise known as carbon capture and storage, or CCS). While UCS supports CCS as a potential climate solution, we believe the term “clean coal” is an oxymoron because of other environmental and public health impacts of using coal across its fuel cycle.

CCS is not a new idea.  The Obama Administration invested about $4.8 billion in CCS and the Bush Administration spent millions on R&D, tax credits and loan guarantees for CCS. Since the primary reason to do CCS is to reduce carbon emissions, one big question is will Trump support funding for CCS if he truly believes climate change is a hoax?

With the Petra Nova project in Texas beginning commercial operation on January 10, and the Kemper project in Mississippi currently scheduled to go online by January 31, coal with CCS technology has reached an important milestone.

Both projects received federal incentives from the U.S. Department of Energy (DOE) that were vitally important to their development. Below I discuss some key lessons learned from these projects, the implications for future projects if Rick Perry becomes DOE Secretary, and the longer-term outlook for CCS as a potential climate solution.

Petra Nova post-combustion CO2 capture project at an existing pulverized coal plant near Houston, TX. Source: NRG.

The tale of two CCS projects

The Petra Nova and Kemper projects have a few similarities and several differences that offer valuable lessons and insights for future CCS projects. Both projects will inject CO₂ into depleted oil fields for enhanced oil recovery (EOR), sequestering the CO₂ while increasing pressure at the aging field to produce more oil and help offset costs. However, the projects use different generation and capture technologies, burn different types of coal, and have considerably different costs (see Table 1).

Petra Nova is a 240 Megawatt (MW) post-combustion capture facility installed at an existing pulverized coal plant near Houston that’s designed to capture 90 percent of the total CO₂ emissions. A joint venture between NRG and JX Nippon Oil & Gas Exploration, the plant uses low sulfur, sub-bituminous coal from the Power River Basin in Wyoming.

Petra Nova was completed on time and on-budget in 2 years for $1 billion. It will also receive up to $190 million in incentives from DOE’s Clean Coal Power Initiative. In addition, NRG and JX Nippon have equity stakes in the oil field where they will be doing EOR, allowing them to capture more value.

Kemper is a new 582 MW integrated gasification combined cycle (IGCC) power plant in Kemper County Mississippi that’s designed to capture 65 percent of the project’s CO₂ emissions prior to combustion when it is still in a relatively concentrated and pressurized form. Owned by Mississippi Power (a subsidiary of Southern Company), the plant will use low-grade lignite coal from a mine next to the plant.

Kemper has been under construction for 6.5 years, is nearly 3 years behind schedule, and the capital cost has more than tripled from $2.2 billion to over $7 billion. It will receive up to $270 million from DOE’s Clean Coal Power Initiative.

One reason for Kemper’s high cost and delay is that they added CCS to a brand new coal IGCC power plant, whereas Petra Nova added CCS to an existing pulverized coal plant. Another reason cited by the New York Times is Southern Company’s mismanagement of Kemper, including allegations of drastically understating the project’s cost and timetable and intentionally hiding problems.

Southern Company’s December filing with the Securities and Exchange Commission (SEC) shows cost increases of $25-35 million per month from Kemper’s most recent delays. They also lost at least $250 million in tax benefits by not placing the plant into service by December 31, 2016.  This is on top of $133 million in tax credits they had to repay the IRS for missing the original May 2014 in-service deadline. In November, they also increased the estimated first year non-fuel operations and maintenance expenses by $68 million.

Customers could pay up to $4.2 billion for Kemper under a cost cap set by the Mississippi Public Service Commission. Southern Company shareholders will absorb nearly $2.7 billion of the cost overruns.

Kemper is also having a negative impact on Fitch ratings for Southern Company. In contrast, Fitch ratings for Cooperative Energy (formerly the South Mississippi Electric Power Association) were recently upgraded from A- to A after bailing out of their 15 percent ownership stake in the project and moving from coal to natural gas and renewables.

Comparison of Kemper and Petra Nova Coal CCS Projects

Sources:  MIT, Global CCS Institute, NRG, Kemper project site.

How many CCS demonstration projects are needed?

In 2008, a UCS report titled Coal Power in a Warming World called for building 5-10 full-scale integrated CCS demonstrations projects at coal-fired plants in the U.S. to test different generation and capture technologies and storing CO₂ in different sequestration sites. Our recommendations were consistent with recommendations from MIT’s 2007 Future of Coal report and a 2007 report by the Pew Center on Global Climate Change. In 2009, former DOE Secretary Steven Chu set a goal for the U.S. to have 10 CCS demonstration projects in-service by 2016. In 2010, the White House Interagency Carbon Capture and Storage Task Force also recommended bringing 5 to 10 commercial demonstration projects online by 2016.

Unfortunately, the U.S. is lagging behind these targets.  While there are 8 large scale CCS projects currently operating in the U.S., Petra Nova is the only large scale CCS project operating at a power plant, according to the Global CCS Institute. Besides Kemper, the only other power plant project listed under development is the Texas Clean Energy Project, which recently lost its DOE funding because of escalating costs and missed deadlines (see more below). The high profile FutureGen project in Illinois was also cancelled after DOE discontinued funding in 2015 because of cost increases and construction delays.

The 110 MW Boundary Dam project in Canada is the only other large-scale power plant coal with CCS project currently operating outside of the U.S.  After encountering several problems during its first year of operation that reduced the capture rate from 90 percent to 40 percent, the project performed much better in 2016.  Before declaring success at Petra Nova and Kemper, these projects will likely also have to go through a similar teething process to work out any bugs in the technology.

Eight more power plant CCS projects are in different stages of development in China, South Korea, the United Kingdom, and the Netherlands.

Rick Perry’s support for coal

Under the Obama Administration, the DOE’s Office of Fossil Energy and the National Technology Laboratory (NETL) have administered a robust Carbon Capture R&D program. The primary goal of this program is to lower the cost and energy penalty of second generation CCS technologies, resulting in a captured cost of CO₂ less than $40/tonne in the 2020-2025 timeframe. Given Perry’s record of supporting coal as Governor of Texas, there’s a good chance he would support continued R&D funding for coal with CCS projects if he becomes DOE Secretary.  Here are a few examples:

• In 2005, Perry issued a controversial executive order to fast-track the permitting process for 11 coal plants (without CCS) proposed by TXU, now called Energy Futures Holdings. UCS and other groups strongly opposed this coal build-out, which would have been disastrous for the climate. Only 3 of the plants were ultimately built.
• In 2002, he supported setting-up a clean coal technology council in Texas.
• In 2009, he signed a bill with tax incentives for clean coal to support projects like the Texas Clean Energy Project, a 400 MW coal gasification with CCS project in West Texas proposed by Summit Power Group. After missing several key deadlines and with the cost nearly doubling to $4 billion, the DOE discontinued funding in May 2016 (after spending $167 million) and asked Congress to reprogram $240 million of the incentives to other R&D efforts. Summit Power said this move would basically kill the project.

The high cost of coal with CCS

CCS advocates often dismiss the high costs of recent projects, arguing that this is expected for first-of-a-kind projects. They claim costs should come down over time through learning, pointing to other technologies like wind and solar as examples.

While it is reasonable to expect that CCS costs will come down, the question is how much and over what time period? Like nuclear power plants, CCS projects tend to be very large, long-lived construction projects that use a lot of concrete and steel, and equipment that is unlikely to be mass-produced in the way more modular technologies like wind turbines and solar panels are manufactured and installed over a much shorter period of time.

Several recent studies project the cost of coal with CCS to be much higher than many other low and zero carbon technologies. For example, the Energy Information Administration’s (EIA) projections from Annual Energy Outlook 2016 show costs for coal with CCS plants in 2022 that are 2-3 times higher than the cost of new onshore wind, utility scale solar, geothermal, and hydropower projects, not including tax incentives (see Table 2 on p. 8). The costs for biopower, advanced nuclear plants, and natural gas combined cycle (NGCC) plants with CCS are also somewhat lower. While EIA projects the costs for coal with CCS plants to decline ~10 percent by 2040, they project the costs for other low carbon technologies to fall by similar or even greater amounts.

Source: EIA, AEO 2016.

EIA’s cost projections are consistent with other sources including NREL’s 2016 Annual Technology Baseline (ATB) report and Lazard’s most recent levelized cost of energy analysis.  They all show that adding CCS to natural gas power plants could be much more economic than coal.

Other studies show CCS applications at industrial facilities could also be less expensive. Industrial applications of CCS could also be more apt—for example in industries such as Iron and Steel and Cement production—where alternative low carbon, affordable technologies don’t exist. In contrast, the power sector has many technologies available today that can generate electricity without carbon emissions.

Role of CCS in addressing climate change

Many experts believe that reaching net zero carbon emissions by mid-century, in line with global climate goals, will likely require some form of CCS, along with nuclear power and a massive ramp-up of renewable energy and energy efficiency. Given the high cost of coal with CCS compared to other alternatives, it’s not surprising that recent studies show it playing a relatively modest role in addressing climate change. However, some studies analyzing the impacts of reducing power sector CO₂ emissions 80-90 percent by 2050 show that natural gas or even biopower with CCS could make a more meaningful contribution after 2040.  For example:

• A 2016 UCS study showed natural gas with CCS could provide 9-28 percent of U.S. electricity by 2050 under range of deep decarbonization scenarios for the power sector, but no coal with CCS (see Figure 5 below). Natural gas with CCS provided 16 percent of U.S. electricity by 2050 under a Mid-Cost Case and 28 percent under an Optimistic CCS Cost Case.
• The November 2016 U.S. Mid-Century Strategy for Deep Decarbonization study released by the Obama Administration at the international climate negotiations in Marrakech found that fossil fuels with CCS would provide 20 percent of U.S. electricity generation by 2050 under their “Benchmark” scenario. While natural gas with CCS made the biggest contribution, both coal and bioenergy with CCS also played a role.
• The 2014 Pathways to Deep Decarbonization in the United States report found that gas with CCS would provide nearly 13 percent of U.S. electricity under their “Mixed” case. They also modeled a High CCS case that “seeks to preserve a status quo energy mix,” in which they assumed CCS would provide 55 percent of U.S. electricity by 2050, split between coal and gas. However, this case also had the highest electricity prices.
• DOE’s 2017 Quadrennial Energy Review found that under a scenario combining tax incentives with successful federal R&D, coal and gas with CCS could provide 5-7 percent of total U.S. generation in 2040. The scenario assumed a refundable sequestration tax credit of $10/metric ton of CO₂ for EOR storage, $50/metric ton of CO₂ for saline storage, and a refundable 30 percent investment tax credit for CCS equipment and infrastructure.

Source:  UCS, The U.S. Power Sector in a Net Zero World, 2016.

Policy implications

Clearly, more DOE-funded R&D is needed to leverage additional private sector investment and demonstrate coal with CCS on a commercial scale using different technologies and at different sequestration sites, like deep saline aquifers. R&D efforts should also be expanded beyond coal to include natural gas and bioenergy power plants, as well as industrial facilities. We also need to develop a strong regulatory and oversight system to ensure that captured CO₂ remains permanently sequestered.

Recent policy proposals to increase tax incentives for CCS could also help improve the economic viability of CCS. A price on carbon and higher oil prices for projects using EOR could also make a big difference, but the likelihood of either happening under the Trump Administration is slim. Given the high cost, long lead time, and limited near-term role of CCS as a climate solution, federal efforts should prioritize R&D and deployment incentives on more cost-effective low carbon alternatives like renewable energy and energy efficiency. While studies show coal with CCS could play a modest role in addressing climate change by 2050, it’s unlikely to be enough over the next four years to fulfill Trump’s promises to revive the coal industry.

New analyses from the Union of Concerned Scientists (UCS), in coordination with the Northeast Solar Energy Market Coalition (NESEMC), shows how Maine, New Hampshire, and Vermont could use modest levels of public funds to greatly increase private-sector investment in clean energy, by offering a more comprehensive approach to financing local clean energy projects.

Together, these three states could leverage $35 million of public funds into a $748 million investment in renewable energy and energy efficiency projects over the next 15 years.

The analysis shows how these states could expand existing clean energy financing programs to make additional low-interest loans and other financial products available to homeowners, businesses, farmers, schools, and municipalities who want to make energy efficiency improvements, install solar panels and wind turbines, or invest in other types of clean energy projects.

A successful track record

The basic approach of clean energy financing programs is to leverage a pool of public-sector funds to garner a larger pool of private-sector investments in renewable energy and energy efficiency. They do this by bringing together a suite of financial products that support the development of clean energy projects. Just as important, these programs raise awareness of clean energy technologies and their benefits and remove barriers to private investments in these resources.

Other Northeast states like Connecticut, New York, and Rhode Island are demonstrating the success of these comprehensive clean energy financing programs. For example, Connecticut and New York have achieved an average leverage ratio across their programs of more than $5 of private funds to every $1 of public funds over recent years. Connecticut has generated nearly $1 billion in clean energy investments since 2012, with 90 percent of that coming from the private sector, while creating almost 8,300 jobs and reducing carbon emissions by 1.4 million tons.

The analysis builds on a series of UCS reports released last year in Michigan, Pennsylvania and Virginia, as well as a report highlighting successful clean energy financing programs already operating in other states and Germany. According to the Coalition for Green Capital, 7 states and 6 countries are operating comprehensive clean energy financing initiatives (see map below).

Building on existing clean energy policies and programs

Maine, New Hampshire, and Vermont already deploy a number of financing programs and incentives to invest in energy efficiency and renewable energy. For example, Efficiency Maine, the New Hampshire Community Development Finance Authority (CDFA), and the Vermont Energy Investment Corporation (VEIC) all offer a variety of financing and incentive programs to increase energy efficiency and renewable energy in homes, businesses, schools, farms, and municipalities. A more comprehensive approach to financing clean energy could expand, enhance, and supplement these laudable programs

All three states also have other proven policies to support clean energy investment including renewable electricity standards, energy efficiency resource standards, public benefits funds, net metering, building energy codes, utility rebates, and property-assessed clean energy financing (PACE).  They are also part of the 9-state Regional Greenhouse Gas Initiative (RGGI), a market based program established in 2009 to reduce power sector carbon dioxide emissions. Revenue collected from the sale of CO₂ allowances under RGGI is also an important source of funding for clean energy programs in all three states.

In addition to complementing existing policies, financing programs have been effective at addressing key market barriers such as providing loans to cover high upfront costs, aggregating loans for smaller projects to make them more attractive to financial institutions, providing underwriting support to help traditional lenders improve their knowledge of new technologies and lower risks, and increasing customer access to low cost capital.

Driving clean energy investments and emission reductions

Based on the experiences of existing clean energy financing initiatives, UCS analyzed the potential impact of expanding clean energy financing in Maine, New Hampshire, and Vermont.  Using the initial $35 million in public funds to create revolving loan programs, with loan repayments regularly returned to the program to fund additional projects, the three states could leverage a $748 million investment in renewable energy and energy efficiency projects over the next 15 years.

By 2031, expanded clean energy investment across these three states could:

• Support the deployment of 190 megawatts (MW) of new solar- and community wind-power projects, producing enough clean power to meet the annual electricity needs of more than 49,000 households
• Save homes and businesses $89 million on their annual electricity bills by investing in efficiency
• Reduce carbon dioxide emissions by more than 513,900 tons, equivalent to taking 97,500 cars off the road

Benefits of expanding clean energy financing in three New England states by 2031

A more coordinated and comprehensive approach is needed

A comprehensive clean energy financing strategy in Maine, New Hampshire and Vermont could be an effective tool for expanding and enhancing existing programs and policies, while leveraging additional private-sector investment, increasing the sustainability of clean energy markets, and improving access to clean energy in low-income communities.

Adding a greater focus on financing—as well as better coordination of programs both within and across the states—could be a cost-effective strategy to help these states reach their long-term goals for clean energy, carbon reduction, and economic development.

One of the headlines this year is EIA’s new projections for renewable energy, which under their reference case is expected to surpass nuclear power by 2020 and coal by 2028 to become the second largest source of U.S. electricity generation after natural gas (see Figure 1 below).

Here are seven key takeaways from AEO 2016 that explain why EIA is projecting such a large increase in renewable energy this year:

1. Federal tax credits and Clean Power Plan drive growth in renewables

EIA’s reference case includes the recent five-year extension of the federal production and investment tax credits for wind and solar passed by Congress in December 2015, and implementation of EPA’s Clean Power Plan (CPP). While the U.S. Supreme Court put a temporary hold on the rule in February 2016 until the merits of the case are decided, EIA decided to include the CPP in the reference case because the rule has not been overturned.

Figure 1. Renewables surpass nuclear power by 2020 and coal by 2028. Renewables include wind, solar, geothermal, biomass, and hydropower. Source: EIA, Annual Energy Outlook 2016.

The federal tax credits, state renewable electricity standards (RESs), and continued cost reductions for wind and solar will drive significant growth in renewables though 2021 (Figure 1). During this time, EIA actually projects natural gas generation to decline slightly as wind and solar are more cost-effective with the tax credits.

After the CPP targets kick in 2022, EIA projects both renewables and natural gas to grow as the two most cost-effective ways (along with a modest increase in energy efficiency) for states to replace coal and comply with the CPP. These results are consistent with recent analyses by UCS, NREL and the Rhodium Group.

2. Wind and solar lead growth in renewables

The renewable energy (including wind, solar, geothermal, biomass, and hydropower) share of U.S. electricity generation grows from 13 percent in 2015 to 24 percent in 2030, and 27 percent in 2040, with almost all of the growth from wind and solar PV (Figure 2).

This is because continued cost reductions are projected for these technologies beyond the 60-70 percent cost reductions already achieved since 2009. Under EIA’s reference case with the federal tax credits and CPP, U.S. wind capacity nearly doubles by 2022, reaching 144 GW, while US solar capacity grows five-fold by 2030, reaching 125 GW. Geothermal increases a significant amount in California and the Southwest, but provides a relatively small share of US electricity generation.

EIA also projects virtually no growth in hydro or biopower. Despite EIA’s inaccurate assumption that all biomass feedstocks are carbon neutral, biopower is still not economically competitive with wind, solar, and natural gas.  The lack of growth in hydro and biomass is consistent with recent analyses by UCS, NREL, and Rhodium Group that include the federal tax credit extension and CPP.

Figure 2. Renewable electricity generation by fuel. Geothermal = red, biomass = gray. Source: EIA, Annual Energy Outlook 2016.

3. Renewable generation increases in all regions of the country by 2030

The biggest increases occur in the West and Plains, which have abundant, low cost wind, solar, and geothermal (Figure 3).  The Southeast also sees a big increase in solar as costs continue to fall.  The Northeast and Mid-Atlantic see a smaller increase in renewables and a bigger increase in natural gas.

The Southeast also sees a modest increase in nuclear generation due to five new reactors currently under construction or operating in Georgia, South Carolina, and Tennessee. This growth offsets a modest reduction in nuclear generation in Mid-Atlantic and Northeast states where EIA assumes a small number of existing plants will retire before their current operating licenses expire. (Note that the retirement of Diablo Canyon in California is not included as the announcement was made after EIA completed its modeling). The Midwest/Mid-Atlantic states also see the greatest reduction in coal generation and the largest increase in natural gas.

Figure 3. Renewables increase in all regions under the Clean Power Plan. Source: EIA, Annual Energy Outlook 2016.

4. Renewables generation varies under different Clean Power Plan implementation scenarios

Figure 4. Cumulative difference in generation in the CPP vs. the no CPP case. Renewables = green, natural gas =blue, and coal = black. Source: EIA, Annual Energy Outlook 2016.

EIA projects renewable generation to increase the most if states chose rate-based rather than mass-based targets as part of their CPP compliance strategies. Broader regional trading with mass-based targets also results in more renewables, less natural gas, and less reduction in coal than the more limited trading assumed in the reference case.

Not surprisingly, in their “extended case” EIA found that continuing to increase the CPP emission reduction targets through 2040 (the current program only goes through 2030) would result in more renewables and natural gas, and less coal than the reference case.

5. Increasing renewable energy is affordable

EIA projects that average retail electricity rates would be 3 percent higher between 2025-2030 in the reference case (with the CPP) than in the no CPP case.  However, total U.S. electricity expenditures would only be 1.3 percent higher in the CPP case over the same period because EIA assumes a modest increase in energy efficiency investments to comply the CPP.

A recent analysis by UCS found that energy efficiency could make a much larger contribution to state compliance with the CPP that would result in cumulative net savings to consumers of $30.5 billion between 2016 and 2030.

6. Renewables are competitive despite lower natural gas prices

While EIA’s natural gas price projection is lower in AEO 2016 than it was in AEO 2015 (Figure 5), large amounts of wind and solar are still competitive due to continued cost reductions and the federal tax credit extension.

EIA projects natural gas prices to double by 2025, due primarily to an increase in LNG exports, and greater natural gas use in the electricity and industrial sectors. The competition from renewables helps avoid greater reliance on natural gas that could increase natural gas prices even further.

Figure 5. Average Henry Hub spot prices for natural gas (2015 dollars per million Btu).

7. EIA is finally using more realistic cost assumptions for renewable energy

UCS has been an outspoken critic of EIA’s pessimistic renewable energy projections and assumptions for many years. We have written several blog posts on the topic and provided input directly to EIA on a few of their analyses and as a participant on several EIA modeling working groups. We also use a modified version of EIA’s National Energy Modeling System (NEMS) in-house to show how renewables could make a larger contribution to the US electricity mix at a much lower cost when using more realistic assumptions.

One of the main reasons why EIA’s projections have fallen short is because they have consistently overestimated the cost of renewable energy technologies like wind and solar. They often lag a few years behind what’s happening on the ground. However, this year is different. For AEO 2016, EIA finally lowered their costs for wind and solar to be more in-line with cost data from a large sample of recent projects, as documented by DOE’s national labs and the national wind and solar trade associations.

In EIA’s defense, their reference case for each AEO only reflects state and federal energy policies that were enacted at the time they do their projections, as discussed extensively in a recent EIA report. With Congress allowing federal renewable energy tax credits to lapse several times before extending them for relatively short periods, and states adopting and increasing renewable electricity standards (RES) many times over the past two decades years, it is somewhat understandable that EIA’s projections of renewable energy development have fallen short of reality.

While future EIA conferences and AEOs may highlight different topics, I’ll remember 2016 as the year EIA turned the corner to show a bright future for renewables.

Our new analysis includes three important updates to our February 2016 analysis that examined the economic benefits of strengthening Illinois clean energy policies, as proposed in the Illinois Clean Jobs Bill:

• Extending the federal tax credits for wind and solar for five years as signed into law in December 2015
• Fixing Illinois’s existing 25 percent by 2025 Renewable Portfolio Standard (RPS) law and adopting a stronger Energy Efficiency Portfolio Standard (EEPS) of 18.5 percent by 2025, as proposed in the ComEd/Exelon bill, except we assume all investor-owned utilities will be required to meet this efficiency target (not just ComEd)
• A scenario assuming the Clinton and Quad Cities nuclear plants retire early (by 2020)

As with our earlier analysis, we assume Illinois will comply with the CPP under all policy scenarios. We do not include Dynegy’s recent announcement to retire 2,800 MW of existing coal capacity, but do include other announced coal plant retirements as of October 2015.

Here are five key findings from our new analysis:

1. Fixing and strengthening the RPS and EEPS provides significant benefits for Illinois’s economy and consumers

Fixing and strengthening Illinois RPS and EEPS lowers household electricity bills

Fixing the existing RPS and adopting the 18.5 percent by 2025 EEPS would generate $8.7 billion in new capital investments in wind, solar, and energy efficiency, while saving homeowners and businesses $3.8 billion on their electricity bills between 2016 and 2030.

A typical Illinois household would save an estimated $84 per year (8%) on their electricity bill by 2030. It would also result in $10 billion in public health and economic benefits by reducing CO₂, SO₂, and NO_x pollution. Strengthening the RPS to 35 percent by 2030 and EEPS to 20 percent by 2025, as proposed in the Clean Jobs Bill, would result in even greater benefits.

2. Fixing and strengthening the RPS and EEPS would help diversify the state’s electricity mix

Renewables and efficiency increase to 27 percent of Illinois electricity generation in 2030 under the fixed RPS/stronger EEPS case and 32 percent under the Clean Jobs Bill case.

Coal and natural gas generation are lower by 2030 to comply with the CPP emission reduction targets, while nuclear generation stays flat (see more below). Both cases result in net exports of electricity from Illinois staying at or near current levels through 2030.

3. Fixing and strengthening the RPS will allow Illinois to capitalize on federal tax credits for wind and solar, creating jobs and economic benefits that would otherwise go to other states

Recent studies by UCS and others show that the federal tax credits extension could result in record-setting levels of new wind and solar development in the U.S. over the next five to seven years. The development is likely to be concentrated in states with strong renewable energy policies.

Other Midwest utilities have already announced plans to ramp up wind and solar to take advantage of the tax credits. For example, Xcel Energy in Minnesota is planing on adding 800 MW of wind and 400 MW of solar by 2020 to capture the benefits of the tax credits, which they claim will save $202 million.

In April, MidAmerican Energy announced plans to add 2,000 MW of wind in Iowa, a $3.6 billion investment that would increase wind power to over 40 percent of Iowa’s electricity. In contrast, Illinois has experienced very little wind and solar development in recent years because of the broken RPS, and only met 60 percent of its RPS target in 2014. This trend is expected to continue unless the RPS is fixed.

4. Projected increases in natural gas prices and establishing a price on carbon under the Clean Power Plan will greatly reduce the economic vulnerability of existing nuclear plants

EIA projects natural gas prices to nearly double by 2025

Despite Exelon’s claims that Clinton and Quad Cities are uneconomic and will be retired early without significant subsidies from the state, our modeling shows it is economically viable to keep these and other existing nuclear plants operating through at least 2030 due primarily to projected increases in natural gas prices.

Our results are consistent with recent modeling by the Energy Information Administration (EIA). EIA’s latest Annual Energy Outlook projects wholesale natural gas prices to increase from $2.62 per million Btu in 2015 to $4.40 per million Btu by 2020 and nearly $5 per million by 2030 (see figure). Like our analysis, the increase in natural gas prices appears to provide enough of a long-term incentive to keep existing nuclear plants operating. While EIA is projecting somewhat lower natural gas prices than last year (our analysis uses EIA’s projection from last year), they still project nuclear generation to stay near current levels over time at the national level.

A price on carbon, which Exelon supports and could help reduce carbon emissions under the CPP, also increases the competitiveness of nuclear plants vs. coal and natural gas, providing an additional incentive to keep Clinton, Quad Cities, and other existing plants operating through 2030.

5. Renewables and efficiency could replace the generation from the Clinton and Quad Cities plants, while allowing Illinois to comply with the Clean Power Plan and save consumers money

Our analysis shows that new renewable generation and efficiency would exceed the retired nuclear generation by 2022 and would be nearly twice as high by 2030 under the fixed RPS/stronger EEPS case.

Electricity bill savings for a typical household are $60 per year (6%) in 2030 under the fixed RPS/stronger EEPS case with the Clinton and Quad Cities plants retired, compared to $84 (8%) without the retirements. However, this does not include Exelon’s proposed subsidies to keep the plants running. While these subsidies are still under negotiation, Exelon has publicly stated that they may need $250 million next year, and $170 million on average over the next 6 years. They claim their proposed bill would cost a typical household 25 cents per month ($3/year).  Other groups estimate the costs could be much higher.

Next steps

While the regular legislative session ended on May 31, we expect conversations will continue throughout the summer. To become a national leader in developing clean energy, our analysis shows that Illinois should at least fix the state’s current 25 percent by 2025 RPS law by transitioning to a full non-bypassable wires charge to create a stable pool of funds for renewables procurement.

Illinois should also extend the proposed increases in energy efficiency to all investor-owned utilities so that all businesses and households in the state can benefits from lower energy bills. In addition, Illinois should maintain its net metering policy and oppose efforts to adopt a mandatory residential demand charge so consumers can fully capture the benefits of installing rooftop solar and so Illinois can attract new jobs in the rapidly growing solar industry.

Update 11/16: Some small edits were made to this post to reflect updated numbers.

Minnesota is one of 19 states that continue to move forward with compliance plans for the Clean Power Plan.

Governor Dayton leads

Last week at a Youth Summit in St. Paul, Governor Dayton promised to veto any legislation blocking or slowing efforts related to the Clean Power Plan.

Dayton addressed questions from 75 high school and college students, also stating that he would “like to see Minnesota’s dependence on coal eliminated” as soon as possible. The summit was focused on advocating for a strong and just Clean Power Plan. Youth also met with their legislators to voice their ideas around equitable implementation of the plan.

Governor Dayton also spoke highly of the Clean Power Plan in the annual State of the State address on March 9. He addressed the Supreme Court stay but noted that developing clean energy to help address the impacts of climate change—which are already being seen by Minnesotans—is too important to put on hold. Decreased snow fall hurting the winter tourism industry, unpredictable growing seasons for farming, and air and water pollution—these are just the beginning of the impacts that Minnesotans have started to see from the effects of burning dirty fossil fuels.

Strong public engagement

Not only is Minnesota pledging to continue working on the Clean Power Plan, but it is acting on its pledge as well. In February and March the Minnesota Pollution Control Agency held eight Clean Power Plan listening sessions across the state to get input from residents about their priorities in shaping Minnesota’s compliance plan.

Each listening session had around 50-100 Minnesotans present, many of them testifying in support of the Clean Power Plan and clean energy development. At the Duluth session, almost the entirety of the audience supported action on climate—in fact, many commented that the plan should go further, faster. Attendees at the Bemidji session questioned the cost of the complying with the Clean Power Plan, while others argued that coal generation will be phased out over time with or without the Clean Power Plan due to market factors like low natural gas prices and the declining costs of wind and solar.

New UCS analysis shows that Minnesota stands to gain

Analysis released by the Union of Concerned Scientists last month shows that Minnesota stands to make major economic gains from the Clean Power Plan, especially when accompanied with increases in the renewable energy standard (RES) and energy efficiency standard (EERS). Prioritizing renewable energy and energy efficiency in Minnesota’s Clean Power Plan compliance plan will maximize the full range of benefits for all Minnesotans.

Our analysis found that combining the Clean Power Plan with a stronger state renewable electricity standard of 40 percent by 2030 and an energy efficiency resource standard that reduces electricity demand by 2 percent per year for all utilities would result in the greatest economic and public health benefits for Minnesota.

For example, this approach would inject more than $5.6 billion in new investments in wind, solar, and energy efficiency projects in Minnesota’s economy between 2016 and 2030, while reducing electricity expenditures for residents and businesses by $745 million.

Pollution control agency filing highlights Minnesota’s progress

In a required filing released earlier this week, the Pollution Control Agency and Department of Commerce explain how they continue to work on Clean Power Plan planning in order to ensure that Minnesota is well-positioned for any litigation outcomes of the Supreme Court ruling.

Sent to energy committee chair leaders and minority chairs, the filing highlighted the extensive technical stakeholder engagement and robust public outreach that Minnesota is already engaging in. It also mentioned that Minnesota is primarily considering trading-ready approaches and expects to participate in the Clean Energy Incentive Program.

Why Minnesota’s leadership is important

While 19 states have indicated that they are moving forward with Clean Power Plan planning, very few are as far along as Minnesota.

Minnesota’s comprehensive and inclusive process with strong public engagement provides an excellent model for other states to replicate. We applaud Governor Dayton and Minnesota regulators for the hard work and dedication to move forward on the Clean Power Plan in order to most effectively plan for Minnesota’s clean energy future.

The tax credit extension provides greater certainty for the renewable energy industry to develop new projects, secure financing and expand U.S. manufacturing capacity. It also allows them to build on recent gains in transitioning the U.S. to a clean energy future, while providing a bridge for states to meet their CO₂ emission reduction targets under EPA’s Clean Power Plan (CPP).

More renewables and CO₂ reductions under a range of natural gas prices

NREL examined the impact of the tax credit extensions under two different natural gas price futures—a base price forecast and a low price forecast—based on Energy Information Administration (EIA) projections. All scenarios include current policies and regulations as of January 1, 2016, including state renewable electricity standards, state and regional carbon emissions policies, and the CPP.

Building on recent gains

Federal tax credits along with state renewable electricity standards have been primary drivers of renewable energy development in the U.S. over the past two decades.  Between 2010 and 2015, new renewable capacity grew at an average rate of nearly 11.6 GW per year.  In 2015, the U.S. added 16.6 GW of new renewable capacity, which was slightly below the U.S. record of 17.6 GW added in 2012.

NREL’s analysis shows that the tax credit extensions will accelerate renewable development (primarily wind and solar), resulting in 48-53 GW of additional capacity by 2022 (Figure 1).  With base natural gas prices, NREL projects:

• Total renewable capacity additions will grow at 18.9 GW per year on average between 2016 and 2020, breaking the 2012 U.S. record, compared with an average of 8.3 GW per year without the tax credit extensions.
• 11.9 GW of new wind capacity and 6.2 GW of new solar capacity would be added each year, on average through 2020, which is slightly below the U.S. record of 13.1 GW of wind installed in 2012 and 7.3 GW of solar in 2015.

Source: NREL.

With base natural gas prices, NREL projects total renewable capacity (from wind, solar, geothermal, hydro, and biopower) to more than double over the next 15 years, reaching ~450 GW by 2030 (18 GW/year on average), with or without the tax credit extensions (Figure 1). The vast majority of this new capacity is wind and solar (Figure 3). While the tax credits accelerate deployment through the early 2020s that result in greater reductions in natural gas and CO₂ emissions (see below), other factors drive the renewables deployment in the mid to late 2020’s that result in similar levels by 2030.  These factors include continued reductions in the cost of renewables, increasing natural gas prices, and compliance with the CPP and state renewable electricity standards.

Source: NREL.

As expected, overall growth in renewable capacity is lower with lower natural gas prices. By 2030, total renewable capacity is projected to reach 356 GW, or 11.3 GW per year on average, with the tax credit extensions (Figure 1).  This growth rate is slightly below the annual average levels achieved in the U.S. between 2010 and 2015.  Like the base gas price case, the tax credit extension accelerates renewable deployment in the early years under the low gas price case, resulting in 48 GW of additional capacity by 2020.  But unlike the base gas price case, renewable capacity is considerably higher (36 GW) by 2030 with the tax credit extension and low gas prices.  This is mainly because zero emissions renewables are displacing more coal generation, which results in about twice the emission reductions per unit of electricity than shifting to natural gas to meet the CPP targets.

Renewables achieve greater emission reductions with lower gas prices

The additional deployment of renewables due to the tax credit extensions displace coal and natural gas generation, resulting in a reduction in power sector CO₂ emissions.  From 2016 to 2030, the tax credit extension results in a cumulative net CO₂ reduction of 540 million metric tons (MMT) under the base gas price case, and 1,420 MMT under the low gas price case (Figure 6).  The two main reasons why emission reductions are greater under the low gas price case are: 1) the ratio of coal to gas generation displaced by renewables is much higher (coal plants are less competitive with lower gas prices) and 2) the incremental level renewable generation is higher over the entire 2016-2030 timeframe.

Source: NREL.

NREL’s analysis shows that the tax credit extension will help states get an early start in meeting their emission reduction targets under EPA’s Clean Power Plan, even as the legal issues around the CPP get resolved.  The additional ~540-900 MMT cumulative reduction in CO₂ emissions achieved by 2025 due to the tax credit extension will also help the U.S. meet its pledge under the Paris Climate Agreement to cut economy-wide emissions 26-28 percent below 2005 levels by 2025.

Other studies show similar results

The results of NREL’s analysis are consistent with another analysis released this week by the Rhodium Group.  This new analysis builds on an analysis Rhodium completed last month using EIA’s National Energy Modeling System (NEMS) that found the tax credit extensions provide a bridge to the clean power plan and change the game for CPP compliance by replacing the need to rely more heavily on natural gas combined cycle plants.

However, their initial analysis used EIA’s pessimistic cost assumptions for renewable energy that are significantly higher than recent industry and NREL estimates. This is something I and my UCS colleagues have blogged about several times.  Rhodium’s new analysis uses the same assumptions as NREL with capital costs that are 43 percent lower for solar PV and 24 percent lower for onshore wind by 2020 compared to EIA. Like NREL, they also analyzed scenarios with lower natural gas prices.

The results are eye opening. Using EIA’s more pessimistic renewables and natural gas assumptions, Rhodium found that new wind and utility scale solar capacity would be highest under a scenario that combines the tax extenders with the CPP (142 GW by 2025) compared to the tax extenders without the CPP (92 GW), and the CPP without the tax extenders (60 GW).  However, when they used the more realistic and updated assumptions for renewables in the tax extender only case, new wind and solar capacity increased to 250 GW with EIA’s base natural gas prices and 163 GW with lower gas prices (Figure 4).

While the Rhodium group analysis clearly shows the best case scenario for renewables is the combination of the tax extenders and the CPP, it also clear that the tax extenders will drive significant deployment of renewables on their own, particularly in the near-term. Which is why they conclude “in all but the low gas price case [and pessimistic renewables costs], the future is bright for wind and solar.”

No more boom-bust cycle for renewables?

Over the past two decades, Congress has allowed the tax credits to expire several times–followed by short-term extensions–that have created a boom/bust cycle for the wind industry. The recent 5-year extension combined with implementation of the CPP through 2030 provides much greater certainty for the U.S. renewable energy industry.  This will allow U.S. to expand its global leadership in advancing clean energy technology, create new jobs, and further drive down costs.  It will also help states avoid an over-reliance on natural gas that could save consumers money, while continuing to make progress in reducing CO₂ emissions that will help meet the CPP targets and the Paris Climate Agreement.  This provides a compelling reason for other states to join the 16 states that have already announced they will move forward with crafting their compliance plans while they await resolution of legal challenges to the CPP.

Flood damage from storm surge during Hurricane Sandy. Photo: Master Sgt. Mark C. Olsen/U.S. Air Force

Sandy shut down or damaged at least 165 electric substations, several large power plants, 7,000 transformers, and 15,000 electrical poles. Storm surge and coastal flooding were major contributors to the damages and subsequent outages. Hospitals had to evacuate patients. Homes and businesses were without power for days and even weeks.

And Sandy wasn’t an isolated incident. Hurricanes Katrina, Rita, and Wilma in 2005, and Gustav and Ike in 2008, also wreaked havoc on the grid. Each knocked out power to one to three million customers and damaged 200 to 500 substations, according to the U.S. Department of Energy.

Despite our growing reliance on electricity, our power grid is increasingly susceptible to failure due to old age and poor condition, and the rate of outages from severe weather has been rising.

The new UCS analysis, Lights Out? Storm Surge, Blackouts, and How Clean Energy Can Help, shows how major power plants and substations are exposed to storm surge flooding from various categories of hurricanes now and in the future in five metropolitan regions: the Delaware Valley, southeastern Virginia, South Carolina Lowcountry, southeastern Florida, and the central Gulf Coast.

Building off three recent UCS reports (Power Failure, Encroaching Tides, and Stormy Seas), the report also highlights the need to better evaluate and plan for these risks, as well as increase investments in protecting the grid and deploying clean energy solutions that will make the grid more resilient AND reduce carbon emissions.

The potential for widespread outages is high and growing

Here are some of our key findings:

• If Category 3 hurricanes hit these five regions today, dozens of power plants and more than 400 hundred major substations could be flooded unless the utilities that own the facilities have taken sufficient steps to protect them. The share of exposed substations ranged from 16 percent in southeastern Florida to nearly 70 percent in the central Gulf Coast.

• Power outages can become widespread once more than a handful of generators or major substations are knocked offline. In all regions examined, the analysis found evidence of the potential for such widespread losses if electricity infrastructure is not sufficiently protected, as floodwater depths could reach 5 to 10 feet, and even 10 to 15 feet at many exposed sites.
• As sea levels rise, coastal flooding from severe storms will reach further inland, and infrastructure in its path will be submerged at greater depths. For example, the analysis found that in southeastern Florida, the number of major substations exposed to flooding from a Category 3 storm could more than double by 2050 and triple by 2070.

You can see maps of other regions showing the power plants and major substations at various inundation levels at different points in time.

Hardening our electricity infrastructure requires foresight

Most coastal infrastructure is designed to meet 100-year flood protection standards based on the Federal Emergency Management Agency (FEMA) flood hazard zones. Unfortunately, these standards are based on historical data that do not incorporate future sea level rise. State and local governments can increase the stringency of these standards, but few have conducted vulnerability assessments to inform that change.

With electricity infrastructure lasting 40 years or more, and sea levels projected to rise by more than a foot by 2050, storm surge could eventually submerge equipment where no such flooding had ever been experienced or was ever expected.

Fortunately, some forward-looking policies and tools are emerging at the local, state, and federal levels to address this problem. Lights Out points to examples from New York, Maryland, Massachusetts, and elsewhere.

The report recommends that utilities consider adding more protective measures, such as natural and artificial buffers, modifying existing infrastructure, such as elevating substations and using submersible equipment—or retiring or moving facilities away from the coastline.

Clean energy: A pathway to resilient power and reduced emissions

Resilient power offers a system that is flexible, can respond to challenges, can quickly recover, and remains available when we need it most. Developing resilient power means shifting away from a centralized electricity system to a more decentralized one designed to meet critical needs even during extreme weather.

When the power goes out, critical facilities typically rely on backup diesel generators until the main electric grid can be restored. However, backup diesel generators present a host of challenges, including being heavily polluting and prone to failure due to infrequent use.

In contrast, clean energy technologies are an attractive alternative to make the grid more resilient while reducing carbon emissions. Some of the most promising clean energy solutions include:

• Renewable energy sources such solar and wind power, coupled with batteries or other energy storage systems, can provide electricity even when the sun sets, the wind stops blowing, or the centralized grid goes dark. The cost of wind and solar has fallen 60-70 percent since 2009, while the cost of battery storage is also declining. When it’s not an emergency, these technologies also generate valuable clean electricity for everyday use.
• Combined heat and power (CHP) plants can greatly increase fuel efficiency while supplying both heat and power to critical facilities.
• Energy efficiency technologies and measures that reduce electricity use in buildings can help save money by reducing the size of the system needed to supply power to critical loads.
• Microgrids can incorporate these distributed clean energy technologies into self-contained systems that generate and consume all the energy within a compact geographical “island”; or they can be interconnected with the broader electric grid and choose when to shift into island mode.

Lights Out points to programs in Florida, Massachusetts, New Jersey, and New York that are deploying these technologies.

Limiting future impacts

The increasing threat of climate-related sea level rise and storm surge to our coastal electricity infrastructure is cause for serious concern. As the single largest contributor to U.S. global warming emissions—representing nearly one-third of total emissions in 2013—the power sector has a critical role to play in ensuring that we avoid the worst impacts of climate change.

While some initial steps have been taken at the local, state, and federal levels to protect the grid and deploy clean, resilient power systems, the investments are not yet up to the scale of the problem. Strong state and federal policies are needed to achieve deep cuts in carbon emissions to limit the severity and cost of future climate impacts.

Implementing the EPA’s Clean Power Plan to reduce carbon emissions from existing fossil power plants—along with adopting and strengthening state renewable energy and efficiency standards and extending federal tax credits—are all important steps for keeping the lights on.

Big Turtle Lake in Bemidji MN where my Dad and I used to fish for walleyes.

After moving to Massachusetts in 1997 to start working at the Union of Concerned Scientists (UCS), my Dad would often send me articles about all the good things Minnesota was doing to advance clean energy to grow the state’s economy and protect the environment.

Fortunately, my job at UCS has given me the opportunity to come back to my home state many times over the past 18 years to help advance the clean energy policies that have made Minnesota a national leader.  Xcel Energy’s announcement October 2 proposing to cut its carbon emissions 60 percent below 2005 levels by 2030—by retiring two units at the state’s largest coal plant (Sherco) in 2023 and 2026 and replacing them with more wind, solar, energy efficiency, and natural gas—continues this legacy.

Xcel’s plan is affordable

In contrast, Xcel’s original plan filed in January would have reduced emissions 40 percent below 2005 levels by 2030.  Xcel’s new plan, described in comments filed with the Minnesota Public Utilities Commission (PUC), aligns with other parties’ comments that much more carbon emission reduction was possible now at low cost.

Xcel’s initial rough estimate is that the revised proposal would likely raise electricity rates by a modest 2-3 percent. They go on to say that including a relatively low value for reducing carbon emission at $21.50 per ton of CO₂ (after 2019) would result in rate impacts near the low end of the range.

An alternative “Clean Energy Plan” developed by several state Clean Energy Organizations (Izaak Walton League of America, Sierra Club, Fresh Energy, Wind on the Wires, and the Minnesota Center for Environmental Advocacy) – using the same computer model as Xcel but with more realistic assumptions – found that similar emissions cuts as Xcel’s revised plan could be achieved at the same cost as Xcel’s original, higher carbon, plan.

They also assumed Xcel could achieve slightly higher levels of cost-effective energy efficiency savings that are still below the levels being achieved in other leading states. Xcel’s new plan agreed and committed the company to meet the state requirement of 1.5 percent per year energy savings.  This will help lower customer electricity bills.

Xcel’s plan prioritizes renewables

Xcel’s revised proposal would accelerate investments in renewable energy by adding 800 MW of wind power and 400 MW of solar power before 2020, and a total 1,800 MW of wind and 1,700 MW of solar by 2030.  According to Xcel, they are doing this to take advantage of lower costs and replace coal:

Advancing renewables benefits our customers in that we can capitalize on favorable market pricing and anticipated tax credits. The acceleration also brings replacement generation online to ensure reliable service for our customers during the Sherco transition.

Figure 1 below from Xcel shows that these new investments would more than double the contribution of wind and solar from about 15 percent of Xcel’s electricity mix in 2015 to 33 percent in 2030.  The increase in renewables would make up for some of the decline in coal generation, while most of the rest would come from increased natural gas generation. In fact, Xcel’s supply today is long on capacity through the middle of the next decade, so the utility does not need a 1-to-1 replacement for the first unit retirement at Sherco.

Source: Xcel

Increasing clean energy is good for Minnesota’s economy

Over the past 15 years, employment in Minnesota’s clean energy sector has more than doubled from 8,600 in 2000 to 15,300 in 2014, according to a 2014 report from the Minnesota Department of Employment and Economic Development. The 78 percent growth in this sector during this time far outpaced the 11 percent growth of the entire state economy, including maintaining steady growth through the recession.

A UCS analysis released earlier this year shows that Minnesota could go even further than Xcel’s proposal and produce 40 percent of its electricity from renewables by 2030, with significant benefits for Minnesota’s economy.   Achieving these targets, as proposed in a bill that was introduced last legislative session, would result in more than $6 billion in new capital investments, $14 million in tax revenues for local communities, and $9 million in payments to landowners that host wind farms. We also found that these benefits could be achieved at a cost of roughly 12 cents per month for a typical household.

According to Xcel, jobs at the Sherco plant would decline from 310 employees currently to 150-160 workers after the two older coal units are retired and replaced with a new natural gas plant and a 50 MW solar array at the site.  At least 35 percent of those workers will reach retirement age in the next few years, and the company is examining transitioning other workers to the new plants and to other Xcel positions.

Xcel’s plan is “the right thing for our customers”

Chris Clark, president of Xcel’s Minnesota regional operations, summed it up best in a recent interview:

This is really a business decision about what we think is right for the future…I think we are going to be industry leaders, but we are really doing this because we think it is the right thing for our customers. It provides certainty to our community and our employees about what our plan is.

As one of Xcel’s former customers, my Dad would agree.  While he passed away in March, he would be very proud of Minnesota’s continued leadership to increase clean energy and address climate change that will allow me to enjoy fishing with my kids for many years to come.

The report highlights six state-level programs (Connecticut, New York, Pennsylvania, Kentucky, Iowa and Massachusetts) and one international program (Germany) that have successfully leveraged private-sector funding to strengthen clean energy investment. These programs range from all-encompassing “green banks” to more discrete efforts focused on a particular clean energy market sector.

State green banks are institutions that provide financial products to assist homes, businesses, and institutions with developing clean energy by leveraging low cost, private-sector capital. Financing costs for these programs are typically lower because the state backing lowers their risk. States have been innovating in this way because of challenges to implementing traditional financing programs. For example, direct incentives programs such as grants and rebates, while effective, can sometimes be difficult to scale up because of cost concerns and administrative complexities. The private sector also has a strong interest in getting in on the economic opportunity afforded by clean energy investments.

Germany’s Green Bank has played a major role in making the country a global leader in renewable energy development.

More capital needed for clean energy

While investments in renewables and efficiency have rapidly increased over the past decade, further increases will be required to meet the growth in energy demand and to limit the worst consequences of climate change. For example, a 2012 National Renewable Energy Laboratory (NREL) study estimated that reaching targets of 30 percent of U.S. electricity generated from renewable energy by 2025 and 80 percent by 2050 will require investment on the scale of $50-$70 billion annually over the next decade.

A key tool in the toolbox

To spur investments in renewables and efficiency, states can adopt a number of proven clean energy market-development mechanisms. The most popular to date have included renewable electricity standards, energy efficiency resource standards, public benefits funds, tax and incentive policies, utility rebates, building-energy codes, net metering, and carbon cap-and-trade programs.

The states highlighted in this report have also used green banks and other financing initiatives to help secure funding for clean energy investments without the need for substantial direct incentives from state coffers. These initiatives complement existing policies, and can also help make renewables and efficiency more competitive, especially as existing policies change, expire, or become less effective. With the costs of renewable energy falling dramatically in recent years, this is also an attractive opportunity for private sector investors looking to participate in the rapidly growing clean energy economy.

These financing programs have also been effective at addressing key market barriers such as high upfront costs, the relative small scale of projects, financiers’ limited understanding of the technology and performance risks, and limited customer access to low cost capital.

An impressive track record

While some programs have a lengthy history of success, others are in their early proof-of-concept stages. Regardless, all seven programs have made impressive progress:

• Connecticut’s Green Bank has completed 8,800 projects and installed solar panels in more than 10,000 Connecticut homes over the past three years, creating 6,200 jobs and reducing carbon emissions by one million tons. The state’s Smart E-Loan and Commercial Property Assessed Clean Energy (C-PACE) programs have leveraged private sector capital at a ratio of 10:1.
• New York’s Green Bank announced its first round of clean energy investments in October 2014, totaling $800 million, which are expected to leverage private sector capital at a ratio of 8:1 and yield returns of 1.5 to 4.1 percent.
• Pennsylvania’s Keystone Home Energy Loan Program (HELP) has supported more than 12,000 residential loans totaling nearly $90 million, with a low loan default rate of 1.3 percent.
• Kentucky’s Home Performance Program has invested $11 million in 1,000 energy efficiency retrofits of single-family homes, achieving average energy bill savings of 26 percent and training some 150 contractors to perform retrofits.
• Iowa’s Alternative Energy Revolving Loan Program has provided $28.6 million in funding for 195 renewable energy projects with total construction costs of $295 million since 1996. The Iowa Green Bank currently offers $50,000 to $500,000 in the form of 1-percent interest loans for up to 10 years.
• Massachusetts’ Mass Save HEAT Loan program financed $180 million in residential energy efficiency projects in more than 21,000 homes between 2006 and 2012. The program provides homeowners and landlords with no-interest loans of up to $25,000 for seven years for a wide range of efficiency and renewable energy technologies.
• Germany’s Kreditanstalt für Wiederaufbau (KfW) Green Bank financed $115 billion in renewables and efficiency projects in more than one million homes between 2011 and 2013, creating hundreds of thousands of jobs and significantly reducing carbon emissions.

The investment potential for clean energy in New York State during the first 10 years of bank operations is more than $75 billion.

As the above programs show, states can use these programs and other existing policies to demonstrate commitments to renewables and efficiency—with quantifiable costs, fossil fuel savings, and carbon emissions reductions-—that can be used to meet EPA’s criteria for complying with the Clean Power Plan. Renewable energy and energy efficiency are two “building blocks” identified by EPA to quantify each state’s emission reduction targets and to demonstrate compliance. States are free to combine any of these building blocks in a flexible manner to meet their targets.

What other states should keep in mind

State clean energy financing programs have been able to successfully engage diverse stakeholders to help mobilize capital. Collaborative efforts have included:

• making use of existing contractor networks to help roll out financing programs
• consulting with the financial community to build trust and identify sustainable funding sources
• drawing on local utilities’ experience delivering programs to avoid duplication.

Consulting with the financial community is important for designing and implementing effective clean energy financing programs.

State agencies have also learned important lessons for administering these programs. This includes using in-house energy expertise to reduce the financial risks of private-sector loans that have enabled a broad array of individuals, businesses, and institutions to achieve savings from clean energy projects.

These seven case studies clearly demonstrate that clean energy financing programs offer a cost-effective approach to help states achieve their Clean Power Plan emissions-reduction targets, while lowering consumer energy bills and generating local economic benefits. By leveraging private-sector capital and reducing the need for taxpayer or ratepayer dollars, these programs have also helped attract bipartisan support.