Projected Effects of the Clean Competition Act of 2025

This report analyzes the projected impacts of the Clean Competition Act (CCA), which proposes a domestic performance standard and a carbon border adjustment mechanism (CBAM) for energy-intensive goods. Using the Global Economic Model (GEM), the authors assess how carbon fees on US manufacturers and analogous tariffs on imports would influence trade, revenues, and emissions. The policy is designed to incentivize lower emissions intensity by taxing carbon levels above a set industry benchmark. The findings suggest that the CCA would shift US imports toward less carbon-intensive countries, such as the UK and Japan, while reducing imports from higher-intensity producers like China, Mexico, and India.

The CCA is projected to significantly reduce global greenhouse gas emissions, with the United States leading the reductions through both improved manufacturing efficiency and decreased demand for energy-intensive goods. While the policy raises substantial government revenue, it also results in slightly lower domestic production in covered sectors like aluminum, steel, and cement due to increased costs for higher-intensity producers. The report notes that the tariffs provide a protective effect for cleaner US manufacturers, but the overall balance of effects leads to small declines in output across most covered and downstream industrial sectors.

Key projections and economic impacts include:

* Global emissions are projected to decrease by 81 million metric tonnes (MMt) in the first year, with US reductions accounting for 63 MMt.

* By the tenth year of the policy, annual global emissions reductions are projected to reach 140 MMt, with US reductions at 119 MMt.

* Total government revenue is projected to be $7.2 billion in the first year and reach $101 billion over the first ten years.

* Domestic output in covered sectors is projected to fall slightly, including cement by -0.02 percent, aluminum by -1.9 percent, and iron and steel by -0.6 percent.

* The policy results in a 0.6 percent output tax equivalent for domestic petroleum refining, contributing to a 0.3 percent rise in imports from zero-tariffed countries.

Rennert, Kevin, Mun Ho, Katarina Nehrkorn, and Milan Elkerbout. *Projected Effects of the Clean Competition Act of 2025*. Report 25-19. Washington, DC: Resources for the Future. December 2025. https://www.rff.org/publications/reports/projected-effects-of-the-clean-competition-act-of-2025/

Life Cycle Air Pollution, Greenhouse Gas, and Traffic Externality Benefits and Costs of Electrifying Uber and Lyft

Abstract 

Transportation network companies (TNCs), such as Uber and Lyft, have pledged to fully electrify their ridesourcing vehicle fleets by 2030 in the United States. In this paper, Aniruddh Mohan, Matthew Bruchon, Jeremy Michalek, and Parth Vaishnav introduce AgentX, a novel agent-based model built in Julia for simulating ridesourcing services with high geospatial and temporal resolution.  The authors then instantiate this model to estimate the life cycle air pollution, greenhouse gas, and traffic externality benefits and costs of serving rides based on Chicago TNC trip data from 2019 to 2022 with fully electric vehicles. They estimate that electrification reduces life cycle greenhouse gas emissions by 40–45% (9–10¢ per trip) but increases life cycle externalities from criteria air pollutants by 6–11% (1–2¢ per trip) on average across our simulations, which represent demand patterns on weekdays and weekends across seasons during prepandemic, pandemic, and post-vaccination periods. A novel finding of their work, enabled by their high resolution simulation, is that electrification may increase deadheading for TNCs due to additional travel to and from charging stations. This extra vehicle travel increases estimated congestion, crash risk, and noise externalities by 2–3% (2–3¢ per trip). Overall, electrification reduces net external costs to society by 3–11% (5–24¢ per trip), depending on the assumed social cost of carbon.

by Aniruddh Mohan, Matthew Bruchon, Jeremy Michalek, and Parth Vaishnav 

https://doi.org/10.1021/acs.est.2c07030

Environmental Science & Technology https://pubs.acs.org/journal/esthag via ACS https://pubs.acs.org

Volume 57, Issue 23, pages 8524–8535; Publication Date: June 1, 2023

India’s proposed Market-Based Economic Dispatch Mechanism Aims to Optimize Power Sector Resources

RMI analysis reveals potential daily savings of INR 1.5–4 crores per day across peak and off-peak seasons in Maharashtra and Tamil Nadu using the MBED mechanism.

RMI’s new report, Transforming India’s Electricity Markets: The Promises of Market-Based Economic Dispatch and the Path Forward, highlights key leverage points for successful implementation of wholesale market reforms that ensures long-term sustainable growth of the power sector in India.

The Indian power sector has evolved rapidly over the past decades, driving economic growth. Now, India has an opportunity to ensure electricity is procured reliably and efficiently, while paving the way for deployment of innovative and flexible power generation technologies. RMI emphasizes that India will need to reform existing wholesale markets to leapfrog toward increasing shares of renewable energy. This warrants a national impetus on resolving financial challenges in the distribution sector, including optimizing power sector resources to strengthen the country’s energy security.

The report outlines the Market-Based Economic Dispatch (MBED) mechanism, creating a shared understanding among stakeholders of the status and impact of proposed changes to India’s wholesale power market. The report provides a summary of the current market design in India, identifies the anticipated benefits of the MBED mechanism, and looks at key barriers toward implementation. It also shares lessons learned from international electricity markets and provides recommendations to successfully transition to the MBED mechanism in India’s power sector.

RMI’s analysis across two states demonstrates cost savings through the efficient dispatch of a pooled generator portfolio and finds potential system cost savings of INR 1.5–4 crore (US$184,000–US$491,000) per day over business-as-usual scenario.

MBED is a step toward creating a system that operates efficiently with an integrated pan-India approach for generators. The report demonstrates how India can ensure that the right electricity market operational structure is in place to develop a reliable, flexible, and cost-effective power sector. RMI Managing Director Clay Stranger said, “The MBED proposal is a key mechanism to optimize India’s power resources and it represents the next major opportunity to further India’s global leadership in advancing the innovative renewable energy sector.”

The full report can be accessed here: https://rmi.org/insight/transforming-indias-electricity-markets/

RMI www.RMI.org
Press Release dated March 1, 2023
https://rmi.org/press-release/indias-proposed-economic-dispatch-mechanism-aims-to-optimize-power-sector-resources/

New Vehicle Standards Will Produce Enormous Benefits for Consumers and the Climate

Updated pollution standards for cars and trucks will cut fuel costs and avoid up to a trillion dollars’ worth of climate-related damages

One April 13, 2023, the Environmental Protection Agency proposed new vehicle standards that will significantly reduce emissions of greenhouse gases and other criteria pollutants from the transportation sector. EPA’s multipollutant standards for light- and medium-duty vehicles sold in Model Years 2027 through 2032 will both reduce pollution and save consumers money—generating substantial societal benefits in the process.

Meredith Hankins, Senior Attorney at the Institute for Policy Integrity at NYU School of Law, issued the following statement: “EPA has a long history of using ambitious emission standards to protect public health, and today’s proposal adds to that history. The proposed standards for passenger vehicles are estimated to result in up to $1 trillion dollars in climate benefits, $280 billion in health benefits from reducing other pollution, and up to $770 billion in avoided fuel costs for consumers. This proposal, and the companion proposal for heavy-duty vehicles, recognize automotive manufacturers’ own commitments to electrify their fleets and build on Congressional incentives in the Inflation Reduction Act. EPA’s proposals represent an achievable path toward increasing the market-share of zero-emission vehicles.”

https://tinyurl.com/2lv9dfbe

Relatedly, the Institute for Policy Integrity filed an Amicus Brief Defending NHTSA Corporate Average Fuel Economy Standards on April 4, 2023.  They noted that in May 2022, the National Highway Traffic Safety Administration (NHTSA) finalized a rule to increase its corporate average fuel economy (CAFE) standards for passenger cars and light trucks for model years 2024–2026. A group of fuel and petrochemical manufacturers and states challenged the standards in the U.S. Court of Appeals for the D.C. Circuit, arguing primarily that the Energy Policy and Conservation Act bars NHTSA from including electric vehicles in the analytical baseline for the new standards. Their amicus brief explains that longstanding administrative guidance and case law direct agencies to develop baselines that reflect their best assessment of the real world absent any new agency action. In the context of this rulemaking, that guidance and case law required NHTSA to project how many and what kinds of vehicles—including electric (and plug-in hybrid electric) vehicles—would be built and sold if it did not issue new CAFE standards, which is what NHTSA did here. Their amicus brief also explains that NHTSA has consistently prepared baselines for prior CAFE standards in this manner.

The Institute for Policy Integrity at New York University School of Law, a non-partisan think tank dedicated to improving the quality of government decisionmaking. The institute produces original scholarly research in the fields of economics, law, and regulatory policy; and advocates for reform before courts, legislatures, and executive agencies. https://policyintegrity.org

Press Release dated April 13, 2023

https://policyintegrity.org/files/media/Vehicle_rule_press_release_2023.0412.pdf

https://policyintegrity.org/projects/update/amicus-brief-defending-nhtsa-corporate-average-fuel-economy-standards

Also see

Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles

A Proposed Rule by the Environmental Protection Agency on 05/05/2023

in the Federal Register

https://www.federalregister.gov/documents/2023/05/05/2023-07974/multi-pollutant-emissions-standards-for-model-years-2027-and-later-light-duty-and-medium-duty

Regional Greenhouse Gas Initiative Would Lower Pennsylvania Emissions, Add to State Revenues, and Have Little to No Impact on Electricity Rates

A new report analyzes the expected impact on Pennsylvania emissions, power generation, revenue, and jobs, offering six central conclusions.  

In 2022, despite fierce opposition, Pennsylvania joined the Regional Greenhouse Gas Initiative (RGGI), a cap-and-trade program designed to reduce carbon emissions from Northeastern and Mid-Atlantic power plants. Ongoing lawsuits have so far prevented the program from going into effect. But what impact would RGGI have on Pennsylvania if the program passes muster?

Researchers at the Kleinman Center for Energy Policy at the University of Pennsylvania and Resources for the Future (RFF) joined forces to find out.  A new report released by the two institutions analyzes the expected impact on Pennsylvania emissions, power generation, revenue, and jobs, offering six central conclusions:  

Joining RGGI reduces Pennsylvania’s electricity sector emissions to 84 percent below 2020 levels in 2030. Without RGGI, the state’s electricity sector emissions would be 52-49 percent below 2020 levels in 2030.

Combined Economic Effects in Pennsylvania

Emissions reductions are achieved with small or negative changes in retail electricity prices. Low allowance prices translate into a small increase (1 percent) in Pennsylvania’s retail electricity prices in 2030 under an annual 3-percent declining emissions cap. When the cap declines to zero by 2040, retail prices see a small decrease (-0.6 percent).  

Joining RGGI decreases coal generation and increases renewable generation in Pennsylvania. Joining RGGI causes coal generation and—to a lesser extent—gas generation to fall in Pennsylvania. Wind and solar capacity and generation increase. 

Joining RGGI decreases Pennsylvania exports slightly, but the state remains a major regional electricity exporter across all scenarios. The increase in renewable generation is not as large as the decrease in fossil generation, leading to a reduction in exports.  

Pennsylvania gains substantial revenue from joining RGGI. While allowance prices are low in 2030 if Pennsylvania joins RGGI, the state still gains $101 to $148 million from the auction of emissions allowances in that year—much of it from allowances sold to generators in other states.

Joining RGGI is unlikely to impact overall employment in the state. Pennsylvania would have the opportunity to use some of the program revenue to benefit communities impacted by the phaseout of coal. 

The team used RFF’s Haiku electricity model to see what would happen if Pennsylvania joined—or did not join—RGGI under two emissions scenarios: one in which RGGI’s emissions “cap” falls 3 percent per year, and one in which the RGGI cap falls at 3 percent per year through 2026 and to zero in 2040.  

The New Economics of Electrifying Buildings - An Analysis of Seven Cities - All-Electric New Homes: A Win for the Climate and the Economy

As states and cities across the United States work to cut carbon emissions from every sector, they’re starting to tackle a crucial transition: eliminating fossil fuels in buildings. Burning fossil fuels, primarily gas, to heat space and water and cook food poses a risk to climate goals and public health. Thus, spurring the shift to modern, electric appliances like heat pumps becomes critical.

...

Buildings are quickly becoming a cornerstone of ambitious climate policy, as policymakers recognize they can’t achieve the necessary science-based emissions reductions without tackling this stubborn sector. This means states and cities across the country won’t meet their climate goals if new buildings in their jurisdiction include fossil fuel systems that lock in carbon emissions over the 50 to 100-year building lifetime.

The cost of such an ambitious transition is often the first consideration. Thus, to help inform these crucial decisions, Rocky Mountain Institute updated and expanded their 2018 analysis, The Economics of Electrifying Buildings. They examined the economics and carbon emissions impacts of electrifying residential space and water heating, now with seven new cities and additional methodology changes. Today, we are releasing the first set of our findings examining newly constructed single-family homes. In every city we analyzed, a new all-electric, single-family home is less expensive than a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. Net present cost savings over the 15-year period of study are as high as $6,800 in New York City, where the all-electric home also results in 81 percent lower carbon emissions over the mixed-fuel home.

Key Findings

The new all-electric, single-family home has a lower net present cost than the new mixed-fuel home in every city we studied: Austin, TX; Boston, MA; Columbus, OH; Denver, CO; Minneapolis, MN; New York City, NY; and Seattle, WA.

• In most cities, the mixed-fuel home (with gas furnace, water heater, air conditioning, and new gas connection costs) has a higher up-front cost than the all-electric home, which uses a heat pump system for both heating and cooling. This is true in Austin, Boston, Columbus, Denver, New York, and Seattle. The Minneapolis climate requires a higher capacity heat pump than other cities in the study. This comes at a higher cost, outweighing the equipment and labor cost savings seen with heat pump systems in milder climates.
• There are significant energy savings with the heat pump space and water heater over corresponding gas appliances, resulting in a lower annual utility cost for the all-electric home in most cities—up to 9 percent lower in Minneapolis. The two modeled scenarios have nearly equivalent utility bills in Boston and Seattle.
• The all-electric home results in substantial carbon emissions savings over the mixed-fuel home in all cities. The greatest savings are found in Seattle (93 percent) and New York City (81 percent). Minneapolis, Columbus, Boston, and Austin all save more than 50 percent over the lifetime of the equipment compared with the mixed-fuel home.

Context and Methodology

Cities in California, Washington, New York, and Massachusetts have all passed laws or adopted codes mandating or encouraging all-electric new building construction. Regional coalitions across the country are forming to extend lessons learned from these first movers to other states, including in New England and the Midwest.

Thus, we extended our Economics of Electrifying Buildings research to assess the economic case for electrification in a variety of climate zones. Several of these states are actively considering new policies or incentives to spur the transition to all-electric buildings.

In partnership with Group 14, we have updated our methodology from the 2018 report to be more readily replicable in support of building decarbonization policy decisions across the United States, incorporating the following:

• A thorough energy use calibration for each scenario to end-use breakdown, energy use intensity, and gas/electricity fuel split with the latest available Energy Information Administration Residential Energy 
• Consumption Survey data by climate region
• A 15-year greenhouse gas emissions comparison that incorporates data from both the US EPA and NREL’s Regional Energy Deployment System model to project changes in carbon intensity for electricity consumed in each state through 2036
• RSMeans construction costing factors to account for location-specific variability in up-front cost
• Building industry performance standards from ASHRAE for HVAC systems, EnergyStar for household appliances, and WaterSense for potable water fixtures

Policy Implications

Our analysis shows that all-electric new construction is more economical to build than a home with gas appliances, regardless of location. Given these findings, policymakers should embrace policies that incentivize or mandate all-electric residential new construction. In addition, they should prioritize complementary policies that address several obstacles that are impeding widespread adoption of all-electric homes. We suggest the following actions:

• Educate contractors. Our research finds that there is low contractor comfort with heat pump systems for year-round heating in cities with severe winter climates, a notion that persists from an era of older technology. Today, there are cold-climate heat pumps designed to address concerns of low capacity and efficiency in cold temperatures, best practice design guidelines, and case studies proving the efficacy of cold-climate heat pumps.To promote contractor readiness as all-electric building codes come online, policymakers and regulatory agencies should establish contractor trainings on heat pump technologies (see for example, NYSERDA’s Clean Energy Workforce Development program and San Jose’s Educational Program). For high rates of participation, ensure attendees have a reason to attend. Some jurisdictions have considered paying participants for their time. Others have allowed trained participants to be added to a qualified contractors list.
• Educate consumers and developers. Consumers and developers are increasingly knowledgeable about modern, efficient heating and cooking technology like heat pumps and induction stoves. But their comfort with the technologies must be fostered to realize the unprecedented market expansion that is needed in the next 10 years to align the buildings sector with our global climate goals.Policymakers and regulatory agencies should establish education campaigns for residents and building developers about the health, economic, and climate benefits of all-electric homes. Familiarizing consumers with induction cooking is a particularly important issue with a variety of novel solutions (see for example, San Jose’s Induction Cooktop Checkout Program).
• Update gas line extension allowances. Typically, gas utilities offer an allowance to compensate a portion of the cost of a new customer gas service extension, with the remainder paid by the customer or developer of the new property. Our research finds that the allowance is highly variable: it could be as low as $1,000 or higher than $5,000, in some states covering the total cost to connect the gas pipeline to a new home. Gas utility customers bear the cost of this allowance over time, therefore socializing the cost of unnecessary, uneconomic infrastructure that is not aligned with air quality, health, or climate goals. Regulatory agencies should reassess these allowances as a part of their transition planning and management of stranded asset risk.
• Address the split incentive challenge through creative financing. In Boston and Seattle, the all-electric home has a lower cost to build, but a slightly higher cost to operate. To ensure that all consumers benefit from the up-front cost savings for all-electric homes, home mortgages could be amortized in a manner to reduce the monthly payments to compensate for higher bills. Additionally, utility regulators and policymakers should work to make the cost of gas reflect the societal cost of greenhouse gas emissions or health impacts. This can be done through a greenhouse gas emissions tax, an air quality/health impacts adder, or an increase in permitting costs for extraction and transport of fossil fuel.

This is the first release of in the new Economics of Electrifying Buildings series. Later this year, we will release findings for single-family retrofits. In early 2021, we plan to provide a detailed technoeconomic analysis for multifamily buildings, examining the case for all-electric new construction and retrofits in all seven cities.

Austin: Single-Family Homes

RMI analyzed the costs of a new all-electric home versus a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. In Austin, the all-electric home saves $4,400 in net present costs and 15 tons of CO2 emissions over a 15-year period.

Key Findings
The new all-electric home has a lower net present cost than the new mixed-fuel home, presenting savings on both up-front costs and utility bills.
• A mixed fuel home (with gas furnace, water heater, air conditioning, and new gas connection costs) has a higher up-front cost than the all-electric home, which uses the heat pump system for both heating and cooling.
• The all-electric home has 7% lower annual utility costs. There are significant energy savings with a heat pump space and water heater over corresponding gas appliances, even though electricity is significantly more expensive than gas per unit energy in Austin.
• Carbon emissions from heating, water heating, and cooking are 65% lower over the appliance lifetime in the all-electric home, due to more efficient appliances and increasingly low-carbon electricity.

Boston: Single Family Home
RMI analyzed the costs of a new all-electric home versus a new mixed-fuel home that relies on gas for cooking, space heating, and water heating. In Boston, the all-electric home saves nearly $1,600 in costs and 51 tons of CO2 emissions over a 15-year period.

New Report Finds Current Transmission Interconnection Process Unworkable and Inefficient, Raising Energy Costs for Customers and Stifling Job Creation

On January 12, 2021 a report was released that shows that the current system for interconnecting generators to the transmission grid is unworkable and inefficient, creating a backlog of unbuilt energy projects. These lengthy interconnection queues have resulted in increased electricity costs for consumers, delayed rural economic development and job creation, and an added difficulty for clean energy projects looking to be connected to the nation’s grid.

Sponsored by Americans for a Clean Energy Grid as part of the Macro Grid Initiative, Disconnected: The Need for a New Generator Interconnection Policy examines the current interconnection process and finds that current policies governing queues are excessively costly, slow, and unpredictable. At the end of 2019, 734 gigawatts of proposed generation — 90 percent of which are new wind, solar, and storage projects — were waiting in interconnection queues nationwide.

“Connecting to the transmission grid is like spending four years at the Department of Motor Vehicles, except the costs are much less predictable. FERC’s interconnection policy was created in a different era and it no longer works,” said Rob Gramlich, co-author and Executive Director of Americans for a Clean Energy Grid.

The report finds that the current interconnection backlog is:

• Increasing electricity costs for American homes and businesses by delaying the construction of new energy projects, which are cheaper than existing electricity production.
• Harming rural economic development and job creation as most new energy projects are located in remote, rural areas.
• Delaying or preventing state, utility, and Fortune 500 companies from reaching their decarbonization commitments by backlogging the development of new renewable energy projects.
• Continuing to expose Americans, especially those in marginalized communities, to the harmful impacts of smog, nitrogen oxide, sulfur oxide, fine particulate matter, and carbon dioxide pollution, which are usually associated with older forms of energy production.

“This report further demonstrates the urgency in which we need to upgrade and reform our transmission system,” says Jay Caspary, co-author and Vice President at Grid Strategies LLC. “We won’t be able to access the benefits of new, clean energy projects by relying on incremental, evolutionary reforms to generator interconnection processes.”

Currently, large transmission upgrades rely on participant funding and network planning, creating a situation in which project developers are charged with paying for transmission upgrades despite the fact that there are broad-based, regional benefits. To address this problem, the report argues that FERC and other planning authorities should discontinue the policy of participant funding for new generation and implement an up-front planning system that expands and improves regional and interregional transmission planning to be proactive, incorporate future generation additions and retirements, and spread costs to all beneficiaries.

“Backlogs in interconnection queues have emerged as a significant challenge to the growth of renewable energy, even as consumer demand increases for low-cost wind and solar projects,” said Gregory Wetstone, President and CEO of the American Council on Renewable Energy (ACORE). “This important new report highlights the shortcomings of current interconnection policies and proposes sensible solutions for substantive reform. The renewable energy growth enabled by these policy changes is essential to efforts to address the climate challenge.”

Executive Summary

America’s system for planning and paying for the nation’s transmission grid is causing a massive backlog and delay in the construction of new power projects. While locally produced electric power is gaining in popularity, most of the lowest cost new power production comes from projects which are located in rural areas and, thus, depend on new electricity lines to deliver power to the urban and suburban areas which use most of the nation’s power. Project developers must apply for interconnection to the transmission network, and until the network capacity is expanded to accommodate the resources, the projects must wait in an “interconnection queue.” At the end of 2019, 734 gigawatts of proposed generation were waiting in interconnection queues nationwide.

This massive backlog has multiple negative impacts on the nation. First, it needlessly increases electricity costs for America’s homes and businesses in two ways: (1) it slows or prevents the adoption of new power sources which are cheaper than existing power generation; and (2) it also significantly increases the costs of each new power source. Americans for a Clean Energy Grid’s (ACEG) recent study demonstrates that a comprehensive approach to building transmission to connect remote power resources to electricity load centers in the Eastern half of the U.S. can cut consumers electric bills by $100 billion and decrease the average electric bill rate by more than one-third, from over cents/kWh  today to around 6 cents/kWh by 2050, saving a typical household more than $300 per year.

Second, because the lowest cost proposed power projects are often located in rural areas, this backlog is blocking rural economic development and job creation. In addition, rural power projects expand the tax base of local communities and typically generate lease payments or other revenue for farmers and other landowners. New transmission in the Eastern half of the U.S. alone will unleash up to $7.8 trillion in investment in rural America and create more than 6 million net new domestic jobs.

Third, almost 90 percent of the backlog is for wind and solar projects, thus blocking the resources which dominate new electricity production, reflecting the changing resource mix in the power sector and America’s abundance of high-quality renewable resource areas where the sun shines bright and the wind blows strong. The U.S. Energy Information Administration (EIA) projects wind and solar will account for 75 percent of new electricity generation in 2020.5 Many states, utilities, Fortune 500 companies and other institutions have adopted large commitments or requirements to scale up their renewable energy use or reduce their carbon pollution and this backlog may delay or impede achievement of these commitments or requirements. In addition, delays in developing these projects unnecessarily exposes Americans, especially those in environmental justice communities, to the harmful impacts of smog, and nitrogen oxide, sulfur dioxide, fine particulate and carbon dioxide pollution.

IV. Evidence of a Broken Interconnection Policy

a) Upgrade costs assigned to customers are high

Analysis by Lawrence Berkeley National Laboratory, shown in tables 1 and 2 below, indicates that the costs to integrate new resources, not just renewable projects, have reached levels that are unreasonably high for a developer to proceed in MISO and PJM. As expected, the costs for integrating new resources in MISO are rising substantially relative to previous years, indicating that the large-scale network has reached its capacity and needs to expand to connect more generation. In other words, much more than “driveway” type facilities are needed; larger roads and highways are required to alleviate the traffic. Table 137 below shows that historically, interconnecting wind projects have incurred interconnection costs of $0.85 per megawatt hour (MWh) or $66 per kilowatt (kW). However, newly proposed wind projects now face interconnection costs that are nearly five times higher, at $4.05/MWh or $317/kW. For reference, this is about 23 percent of the capital cost of building a wind project.

New solar projects in MISO South have much higher upgrade costs. The most recent 2019 system impact study for solar projects in MISO South estimated upgrade costs to total $307/kW, with upgrade costs for individual interconnection requests as high as $677/kW.

The rapidly increasing cost of interconnection in recent years shows that the breaking point has been reached. MISO, for example, has reported that “...interconnection studies for new generation resources in MISO’s West sub-region have indicated the need for network upgrades exceeding $3 billion to accommodate the initial queue volume, and a similar trend is expected to occur in other areas with high wind and solar potential, including MISO’s Central and South sub-regions.” Figure 2 below illustrates the large increase in assigned network upgrade costs to generators in MISO West, from approximately $300/kW in 2016 to nearly $1,000/kW in 2017. The costs to build proposed wind projects will likely result in developers abandoning those resources as project integration costs exceed $100/kW.

Sources of Cost Overrun in Nuclear Power Plant Construction Call for a New Approach to Engineering Design

Highlights

• US nuclear plant cost estimation does not align with observed experience

• “Indirect” expenses, largely soft costs, contributed a majority of the cost rise

• Safety-related factors were important but not the only driver of cost increases

• Mechanistic models inform innovation by relating engineering design to cost change

Summary

Nuclear plant costs in the US have repeatedly exceeded projections. Here, we use data covering 5 decades and bottom-up cost modeling to identify the mechanisms behind this divergence. We observe that nth-of-a-kind plants have been more, not less, expensive than first-of-a-kind plants. “Soft” factors external to standardized reactor hardware, such as labor supervision, contributed over half of the cost rise from 1976 to 1987. Relatedly, containment building costs more than doubled from 1976 to 2017, due only in part to safety regulations. Labor productivity in recent plants is up to 13 times lower than industry expectations. Our results point to a gap between expected and realized costs stemming from low resilience to time- and site-dependent construction conditions. Prospective models suggest reducing commodity usage and automating construction to increase resilience. More generally, rethinking engineering design to relate design variables to cost change mechanisms could help deliver real-world cost reductions for technologies with demanding construction requirements.

...

The history of nuclear energy in the US is one of mixed results. Rapid capacity growth in the 1960s was accompanied by significant unit upscaling, followed by operational improvements and rising capacity factors. But in the 1970s, rising project durations and costs, alongside studies on thermal pollution and low-level radiation, became a source of public controversy. Following the 1979 Three Mile Island accident, a long hiatus of nuclear construction began. Rising construction costs and project delays have continued to affect efforts to expand nuclear capacity in the US since the 1970s. A survey of plants begun after 1970 shows an average overnight cost overrun of 241%. Since the 1990s, two nuclear projects have begun construction, both two-reactor expansions of existing generating stations. The VC Summer project in South Carolina was abandoned in 2017 with sunk costs of $9B, and the Vogtle project in Georgia is severely delayed. Current estimates place the total price of the Vogtle expansion at $25B ($11,000/kW), almost twice as high as the initial estimate of $14B, and costs are anticipated to rise further.

Challenges in nuclear construction are not unique to the US. Recent projects in Finland (Olkiluoto 3) and France (Flamanville 3) have also experienced cost escalation, cost overrun, and schedule delays. Cost estimates for a plant under construction in the United Kingdom (Hinkley Point C) have been revised upward. In contrast to the experience in Western Europe and the US, however, China, Japan, and South Korea have achieved construction durations shorter than the global median since 1990. Cost and construction duration tend to correlate (e.g., Lovering et al.), but it should be noted that cost data from these countries are largely missing or are not independently verified. (Cost data should be provided and audited by entities not actively involved in plant procurement and construction, including data from international organizations or government agencies as opposed to data from utilities and reactor equipment providers.)

[The researchers concluded that between 1976 and 1987, indirect costs—those external to hardware—caused 72% of the cost increase. “Most aren’t hardware-related but rather are what we call soft costs,” says Trancik. “Examples include rising expenditures on engineering services, on-site job supervision, and temporary construction facilities.”]

Percentage contribution of variables to increases in containment building costs These panels summarize types of variables that caused costs to increase between 1976 and 2017. In the first time period (left panel), the major contributor was a drop in the rate at which materials were deployed during construction. In the second period (middle panel), the containment building was redesigned for improved safety during possible emergencies, and the required increase in wall thickness pushed up costs. Overall, from 1976 to 2017 (right panel), the cost of a containment building more than doubled.

As the left and center panels above show, the importance of those mechanisms changed over time. Between 1976 and 1987, the cost increase was caused primarily by declining deployment rates; in other words, productivity dropped. Between 1987 and 2017, the containment building was redesigned for passive cooling, reducing the need for operator intervention during emergencies. The new design required that the steel shell be approximately five times thicker in 2017 than it had been in 1987—a change that caused 80% of the cost increase over the 1976–2017 period.

Utilities Exploit Market Loopholes, Costing Midwest Consumers $350 Million in 2018 - Study Finds Nearly One Fifth of Coal Generation the Midwest Operated Uneconomically

Regulated monopoly utilities overcharged millions of U.S. ratepayers in the Midwest at least $350 million in 2018 by selling them power from coal plants instead of from lower-cost, cleaner sources, according to a study released today by the Union of Concerned Scientists (UCS).

Consumers paid an average of $5 a month and as much as $184 a year in increased electricity costs that pay for monopoly utility practices that clog up the grid with dirty, expensive coal power and deprive less polluting resources grid access and revenues.

“Our analysis shows millions of customers are forced to subsidize utilities’ coal-fired power plants without even realizing it,” said Joe Daniel, senior energy analyst at UCS and co-author of the report “Used, But How Useful? How Electric Utilities Exploit Loopholes, Forcing Customers to Bail Out Uneconomic Coal-Fired Power Plants.” “Utilities have been hoodwinking regulators and ripping off their customers to prop up their uneconomic coal plants when lower-cost resources are readily available,” added Daniel.

Power markets are set up so that the lowest-cost resources should operate when they are available. But monopoly utilities, which build and operate power plants that directly serve retail customers, are able to exploit loopholes in the market rules at the expense of consumers. One example is “self-committing,” which allows the company to sell power from its own, uncompetitive coal plants at a loss instead of from cheaper, cleaner energy sources.

If the energy resources in the Midcontinent Independent System Operator (MISO) market were dispatched economically, consumers would have saved approximately $350 million dollars in annual electricity bill costs in 2018. Furthermore, the coal fleet across MISO would run 19 percent less and allow cheaper, cleaner generation access to the market. These consumer savings stem from a reduction in regulated utilities’ fuel and operations costs.

“Power from coal plants is expensive because the fuel isn’t cheap and the plants cost a lot to operate compared to other resources available in the market,” said Daniel. “But some utilities will sell power from coal plants at a loss, banking on being able to recoup those losses on the backs of captive customers.”

Utilities and regulators are supposed to check to make sure they are truly putting the least expensive power on the grid, but in MISO, they often don’t spot the problem. The report notes that public utility commissions, which regulate monopoly utilities and determine what costs they are allowed to recover from ratepayers, also are usually unaware that they are greenlighting a utility bailout.

“Allowing uneconomic self-commitment of coal-fired power plants in those markets diverts precious consumer dollars away from improving market efficiency and wastes dollars that could otherwise reduce greenhouse gas emissions,” said Jon Wellinghoff, former chair of the Federal Energy Regulatory Commission and CEO of GridPolicy, Inc. “If we are going to move rapidly to the low-carbon future necessary to avert climate disaster we need to be as efficient as possible in the operation of wholesale electric markets.”

Daniel and his co-authors analyzed the MISO market, which provides power to 15 states. The report explored a most efficient way to use existing energy resources in the area, using the same modeling tool that MISO operators and many utility companies use when making their own market forecasts.

According to the analysis, the following utilities sold the most coal-powered electricity when less expensive electricity was available from market sources in 2018:

Cleco Power LLC, which provides power to more than 240,000 families in Louisiana, uneconomically generated electricity from its Dolet Hills and Brame Energy Center coal plants, at a $123.3 million loss in 2018. If utilities in MISO ran their power plants more efficiently, the average family in Louisiana could have saved $15 a month in electricity bills, or a total of $184 that year.

DTE Electric Company, which also provides power to nearly 2 million families in Michigan, uneconomically generated power from its five coal plants—Belle River, Monroe, River Rouge, St. Clair and Trenton Channel—at a $94.7 million loss in 2018. If utilities in MISO ran their power plants more efficiently, the average family in Michigan could have saved $5 a month in electricity bills, or a total of $61 that year.

Why did renewables become so cheap so fast? And what can we do to use this global opportunity for green growth?

Summary

...

Fossil fuels dominate the global power supply because until very recently electricity from fossil fuels was far cheaper than electricity from renewables. This has dramatically changed within the last decade. In most places in the world power from new renewables is now cheaper than power from new fossil fuels.

The fundamental driver of this change is that renewable energy technologies follow learning curves, which means that with each doubling of the cumulative installed capacity their price declines by the same fraction. The price of electricity from fossil fuel sources however does not follow learning curves so that we should expect that the price difference between expensive fossil fuels and cheap renewables will become even larger in the future.

This is an argument for large investments into scaling up renewable technologies now. Increasing installed capacity has the extremely important positive consequence that it drives down the price and thereby makes renewable energy sources more attractive, earlier.... Falling energy prices also mean that the real income of people rises. Investments to scale up energy production with cheap electric power from renewable sources are therefore not only an opportunity to reduce emissions, but also to achieve more economic growth – particularly for the poorest places in the world.

...

Today fossil fuels – coal, oil, and gas – account for 79% of the world’s energy production and as the chart below shows they have very large negative side effects. The bars to the left show the number of deaths and the bars on the right compare the greenhouse gas emissions. My colleague Hannah Ritchie explains the data in this chart in detail in her post ‘What are the safest sources of energy?’.

This makes two things very clear. As the burning of fossil fuels accounts for 87% of the world’s CO2 emissions, a world run on fossil fuels is not sustainable, they endanger the lives and livelihoods of future generations and the biosphere around us. And the very same energy sources lead to the deaths of many people right now – the air pollution from burning fossil fuels kills 3.6 million people in countries around the world every year; this is 6-times the annual death toll of all murders, war deaths, and terrorist attacks combined.1

It is important to keep in mind that electric energy is only one of several forms of energy that humanity relies on....2

What the chart makes clear is that the alternatives to fossil fuels – renewable energy sources and nuclear power – are orders of magnitude safer and cleaner than fossil fuels.

...

Fossil fuels dominate the world’s energy supply because in the past they were cheaper than all other sources of energy. If we want the world to be powered by safer and cleaner alternatives, we have to make sure that those alternatives are cheaper than fossil fuels.

The price of electricity from the long-standing sources: fossil fuels and nuclear power

The world’s electricity supply is dominated by fossil fuels. Coal is by far the biggest source, supplying 37% of electricity; gas is second and supplies 24%. Burning these fossil fuels for electricity and heat is the largest single source of global greenhouse gases, causing 30% of global emissions.3

The chart here shows how the electricity prices from the long-standing sources of power – fossil fuels and nuclear – have changed over the last decade.

To make comparisons on a consistent basis, energy prices are expressed in ‘levelized costs of energy’ (LCOE). You can think of LCOE from the perspective of someone who is considering building a power plant. If you are in that situation then the LCOE is the answer to the following question: What would be the minimum price that my customers would need to pay so that the power plant would break even over its lifetime?

Study Finds Energy Storage Can Save Long Island Electric Customers $390 million over the Next Decade - Replacing 2,300MW of Fossil-Fueled Peaker Power Plants with Energy Storage by 2030 can save customers money, maintain electric grid reliability and reduce air pollution

A new study released by the New York Battery and Energy Storage Technology Consortium (NY-BEST), in partnership with the consulting firm, Strategen, finds that more than 2,300 MW of fossil fueled “peaking” power plants on Long Island can be cost-effectively replaced with energy storage over the next decade, saving Long Island customers more than $390 million over the next ten years and significantly reducing harmful air pollutants. The study, conducted by Strategen, examined the operations of Long Island’s aging fleet of fossil-fueled “peaker” plants, those power plants that operate primarily only during high demand or “peak” times. The analysis shows that it is technically feasible and cost-effective to replace more than 2,300 MW of Long Island’s 4,300 MW fossil-fueled peaker plants with energy storage over the next decade. It also finds that approximately half of the peaker plants, around 1,100 MW, could be retired and replaced with energy storage by 2023. The remaining 1,200 MW could be replaced by 2030, in conjunction with New York State’s plans to increase solar energy, energy efficiency measures, and offshore wind resources.

“Replacing Long Island’s oldest, least efficient, and most polluting fossil-fueled peaker plants today with lower cost, emission-free energy storage is a no-regrets solution for the Long Island Power Authority (LIPA), PSEG Long Island, Long Island electric customers, the environment, and the State of New York, said Dr. William Acker, Executive Director of NY-BEST. “As we work to achieve New York’s nation-leading and mandated goals for a carbon-free electric grid by 2040, energy storage is an essential proven technology that will enable renewable energy, maintain reliability, reduce emissions and provide a resilient electric grid.”

ATehachapi Energy Storage Project, Tehachapi, California
https://en.wikipedia.org/wiki/Battery_storage_power_station 

As part of New York State’s commitment to halting climate change, the State has mandated a carbon-free grid by 2040. The study released October 28, 2020 examines the cost-effectiveness of retiring Long Island’s aging and inefficient fossil-fueled peaker fleet and replacing it with energy storage, a “low-hanging fruit” in the Island’s energy transition. The analysis shows that replacing the aged, polluting peaker fleet will reduce energy costs, create jobs, build a more resilient power system, and reduce air pollution and greenhouse gas emissions in communities across Long Island, including Potential Environmental Justice Areas.

Long Island is home to 26 fossil-fueled power plants, composed of 74 individual turbine units, that seldom operate yet impose significant costs on Long Island electric customers. Of LIPA’s portfolio of 5,667 MW of fossil-fueled generators, 4,357 MW are “peaker plants” that operate at an annual capacity factor of 15% or less (i.e., roughly 15% of the time).

To maintain these peakers, LIPA customers pay an estimated $473 million annually in capacity costs, almost three times the market rate for capacity resources cleared through NYISO’s competitive markets.

Retiring and replacing these aging assets has the potential to create $10.5 million of annual savings in 2021, growing to $150 million annually in 2030. Over the next decade, fossil peaker replacements could save LIPA customers as much as $393 million, representing savings of approximately $360 per household across LIPA’s 1.1 million customers.

“This important and timely study demonstrates the significant potential and cost savings for energy storage on Long Island as we transition to 100% zero-carbon electricity,” said Gordian Raacke, Executive Director of Renewable Energy Long Island. “The findings make it clear that we can take steps today to replace many of Long Island’s antiquated and polluting fossil-fueled power plants with energy storage while saving consumers money.”

"This groundbreaking study shows that, over the next decade, fossil-fuel peakers on Long Island can reliably be replaced by cleaner and cheaper battery storage, along with renewables and efficiency investments,” said Lewis Milford, president of Clean Energy Group, a national nonprofit that works on peaker replacement issues. “In addition to its importance in this New York region, this study gives other cities and states a good roadmap on how to replace the hundreds of dirty, expensive fossil-fuel peakers that now pollute environmental justice communities in other parts of the country.”

“Fossil-fueled peaker plants are dirty, expensive and disproportionately harm environmental justice communities. This study shows what we’ve long known to be true – New York can replace its pollution emitting peaker plants with emissions-free energy storage while saving consumers money. It’s a win-win. Achieving New York’s nation-leading climate goals requires that we go all-in on clean energy solutions, and fast. Scaling-up energy storage must be part of New York’s climate strategy – not only on Long Island, but all across the state,” said Chris Casey, Senior Attorney at NRDC.

The full Report can be viewed here https://www.strategen.com/reports-1/ny-longisland-peaker.

Key results of this study show: 

• It is feasible and cost-effective to replace 1,116 MW of Long Island’s fossil-fueled peaker plants with energy storage by 2023 and over 2,300 MW by 2030.
• Potential savings of up to $393 million of savings can be achieved for LIPA customers over the next decade by retiring and replacing aging fossil assets.
• Replacing peakers with storage will eliminate 2.65 million metric tons of CO2, 1,910 tons of NOx, and 639 tons of SO2 of emissions annually, resulting in societal benefits of $163 million annually.
• Of the 2,300 MW of fossil peaker plant replacements, 334 MW could be retired and replaced immediately, and another 782 MW could be phased out by 2023, coinciding with the implementation of local emission control regulations and the expiration of existing LIPA long-term contracts.
• In the East End of Long Island there is a near-term opportunity for up to 90 MW of fossil peakers to be displaced with energy storage, and additional opportunities over time as local constraints are addressed.

The New York Battery and Energy Storage Technology (NY-BEST) Consortium www.ny-best.org is a non-profit corporation and industry-led consortium with more than 185 organizational members. NY-BEST’s mission is to catalyze and grow the energy storage industry and establish New York State as a global leader in the energy storage industry. 

Press Release dated October 28, 2020

Combining information on others’ energy usage and their approval of energy conservation promotes energy saving behaviour

Households reduced their electricity use the most when they learnt both that they were using more energy than their neighbours and that energy conservation was socially approved. This suggests that efforts to use social information to nudge conservation should combine different types of social feedback to maximize impact.

Messages for Policy

• The content of social information messages determines their impact on energy conservation.
• Combining descriptive information on neighbours’ efficient energy usage and injunctive social approval for energy efficiency maximizes the effectiveness of social information.
• Delivering inconsistent descriptive and injunctive information reduces the impact of each piece of feedback.
• Simply adding more pieces of feedback of the same type has a limited effect.

Based on J. Bonan et al. https://doi.org/10.1038/s41560-020-00719-z (2020).

The policy problem

Home Energy Reports (HER) are a popular means of encouraging energy conservation, reaching millions of energy utility customers across many countries. HERs typically rely on social information about the energy usage of a customer’s neighbours (descriptive feedback) and their social approval of energy conservation (injunctive feedback) to nudge recipients toward more energy-efficient behaviour. The specific content of both types of feedback depends on how the recipient’s energy usage compares to that of their neighbours (Fig. 1). Available evidence indicates that the impact of HERs on energy consumption varies significantly both across countries and across individuals. This raises the question of whether the heterogeneity in the effectiveness of HERs can be attributed to how social information feedback is conveyed. Answering this question could inform the design of more effective communication campaigns relying on social information.

Fig. 1: Home Energy Report.

a–c, Layout and content of a Home Energy Report for a user receiving three thumbs-up (a); and a user receiving two thumbs-up (b). Both versions of the report contain injunctive feedback, that is, the thumbs-up (top), and descriptive feedback, that is, the bars displaying actual energy consumption (bottom). The figure also displays the position of the randomized descriptive or injunctive norm primes, whose text is shown in (c). Reproduced from Bonan, J., Cattaneo, C., d’Adda, G. & Tavoni, M. Nat. Energy https://doi.org/10.1038/s41560-020-00719-z (2020). Copyright 2016-2020

The findings

Energy customers who received two different types of social feedback (descriptive and injunctive) encouraging them to save energy reduced their consumption more than low-energy users for whom conforming with the descriptive feedback would entail consumption increases, at odds with the injunctive feedback praising energy saving. The addition of a second piece of information of the same type (for example, adding a second descriptive messages that encouraged energy saving) had a limited impact. When feedback was inconsistent, the piece of feedback delivering the strongest message prevailed, where strength reflected the difference between the user’s energy consumption and that of their neighbours (descriptive feedback) and the intensity of social approval conveyed through visual cues (injunctive feedback). These results suggest the significance of synergies between different types of feedback, rather than the superiority of any one type of feedback. The results may be specific to the precise wording and graphical representations used to provide feedback in our HER (Fig. 1), and may not generalize to the whole customer base.

The study
We carried out a randomized controlled experiment in Italy in which households received HERs. We disentangled the impact of descriptive and injunctive feedback in two ways. First, we exploited the discontinuities in the injunctive feedback, which changed discretely as users’ consumption crossed certain thresholds, for instance shifting from one to two ‘thumbs-up’ as a user’s consumption dropped below the average of their neighbours. Second, we randomly assigned customers to receive a message at the bottom of the HER emphasizing either a descriptive or an injunctive norm of energy conservation (Fig. 1). Using data on the content of the HERs received by users and on their energy consumption, we were able to evaluate the impact of each piece of feedback in isolation, and when combined with others of the same or of different types.

https://www.nature.com/articles/s41560-020-00727-z
by Jacopo Bonan, Cristina Cattaneo, Giovanna d’Adda & Massimo Tavoni 
Nature Energy Policy Brief https://www-nature.com/nenergy/

Volume 5, Published: 02 November 2020; Pages 832–833 (2020)

The main article "The interaction of descriptive and injunctive social norms in promoting energy conservation" by the same authors published on the same day at https://www.nature.com/articles/s41560-020-00719-z (pages900–909) notes

.....
the magnitude of the average savings from the programme (−0.353%) is outside the range of those generated by similar ones in the United States (minimum = 0.88%, maximum = 2.55%), they are in line with the existing evidence from Europe. Various factors, such as lower average consumption in Europe than that in the United States, the specific features of the programme we studied or differences in beliefs across contexts, may be responsible for these differences. The heterogeneous effects, although not robust and only marginally statistically significant, are qualitatively in line with the existing evidence on the larger impact of social information on high electricity users and on the absence of boomerang effects among low users

These results provide initial, albeit weak, support for our conceptual framework. For high users, normative and injunctive feedbacks pull behaviour in the same direction, which results in a reduction in electricity almost twice as large as that in the average treatment effect. For low electricity users, conforming to the reference groups’ behaviour motivates a consumption increase (’boomerang’), but the injunctive feedback included in the eHER counterbalances the negative effect of the descriptive feedback. 

We Energies to retire 1.8 gigawatts of fossil fuel; utility adding solar, wind, battery storage

Wisconsin’s largest utility plans to replace nearly half its coal-fired generation with a portfolio of solar, wind, batteries and natural gas plants as part of a $16.1 billion spending plan that the company says will generate profits for investors and save money for ratepayers.

WEC Energy Group plans to retire 1,800 megawatts of fossil fuel generation — including the South Oak Creek coal plant near Racine — over the next five years while adding 1,500 megawatts of clean energy and storage capacity along with 300 megawatts of natural gas generation.

Oak Creek, Wis., coal-fired electrical power stations. 

Coburn Dukehart/Wisconsin Watch

https://www.wpr.org/states-largest-utility-will-retire-1-800-megawatts-fossil-fuel-generation

Utility chairman Gale Klappa announced the capital plan during a call with investors Tuesday, in which he said it would help WEC meet its goal of carbon neutral electricity by 2050 and achieve a 55% reduction in carbon emissions by 2025.

Klappa said the spending plan, which is $1.1 billion larger than the previous five-year plan, will increase company profits by 5% to 7% a year while also saving ratepayers what amounts to $50 million a year over the next two decades.
...
In broad terms, the plan calls for building 800 megawatts of solar generation and 100 megawatts of wind generation coupled with 600 megawatts of battery storage, which can be used to balance those intermittent renewable resources.

“The data show that battery storage has now become a cost-effective option for us,” Klappa said.

The announcement comes as Wisconsin’s first utility-scale solar plant came online. Jointly owned by WEC subsidiary Wisconsin Public Service Corp. and Madison Gas and Electric, the 150-megawatt Two Creeks Solar Farm in Manitowoc County began commercial operation Monday.

Curtis Waltz Wisconsin Public Service Corp

WEC also intends to purchase a 200-megawatt share of Alliant Energy’s new West Riverside natural gas plant and build 100 megawatts of natural gas-powered peaking plants.

The company said those acquisitions will allow it to retire the 1,100-megawatt South Oak Creek power plant, whose four generators are all more than 50 years old, in 2023 and 2024.

WEC’s oldest coal-fired plant, South Oak Creek is the single largest source of toxic metals dumped into Lake Michigan, according to a Chicago Tribune analysis of federal data.

Last year, the Department of Natural Resources gave WEC until the end of next year to stop using water to remove ash from the boilers, a process that can lead to mercury and other toxins seeping into groundwater.
...
Klappa said closing an older plant like South Oak Creek could save $50 million a year in operational and maintenance costs.
...
Consumer advocates cautioned that ratepayer savings will depend on how regulators handle the hundreds of millions of dollars WEC has invested in fossil fuel plants over the past two decades.
...
On Thursday the Public Service Commission approved a plan for WEC to refinance $100 million of its remaining investment in pollution controls at its Pleasant Prairie coal plant, which WEC retired in 2018 saying it would save millions of dollars for ratepayers.  The financing arrangement, known as securitization, is expected to save ratepayers about $40 million.  Consumer and environmental advocates, as well as regulators, say securitization could be a key tool for paying off plants that are no longer economic to run.

Despite attempts by the Trump administration to prop up the coal industry, South Oak Creek is the 329th U.S. coal plant targeted for retirement since 2010, according to the Sierra Club.  Over the past decade, U.S. utilities have retired or replaced 95,000 megawatts of coal-fired capacity in response to tighter air pollution standards and increasingly unfavorable economics, according to the Energy Information Administration. Another 25,000 megawatts of coal capacity are expected to retire by 2025.  In the first six months of 2020, the U.S. electric power sector consumed 30% less coal than in the first half of 2019, according to recent data from the EIA.
...
Alliant Energy, which plans to add 1,000 megawatts of solar generation in Wisconsin, this year has announced plans to close its 415-megawatt Edgewater plant in Sheboygan by the end of 2022, while the company’s Iowa utility said last month it would also close a 275-megawatt coal plant in Lansing on the Mississippi River.

FOR FULL STORY GO TO:

https://www.kenoshanews.com/news/state-and-regional/we-energies-to-retire-1-8-gigawatts-of-coal-replace-with-solar-batteries-gas

by Chris Hubbuch 
Kenosha News https://www.kenoshanews.com

November 6, 2020

also see https://www.wpr.org/states-largest-utility-will-retire-1-800-megawatts-fossil-fuel-generation

Building Performance Standards: Lessons from Carbon Policy

Summary:

This paper reviews the relevant design elements of carbon and environmental markets and explores how they could influence the design of Building Performance Standards (BPS) programs. Carbon and environmental markets have existed for more than three decades, giving policymakers experience with scope and target setting and the design of flexibility provisions. The paper also sketches out how the sector-specific BPS programs overlap and interact with existing cross-sectoral programs—state-level clean energy and renewable portfolio standards (RPS), the Regional Greenhouse Gas Initiative (RGGI), electricity markets, and transport electrification.

...

Discussion

BPS programs can use several design options pioneered in the carbon markets— multiyear compliance periods, absolute or benchmarked targets, and various flexibility mechanisms—to provide flexibility, help balance environmental goals and compliance costs, and even generate revenues to fund related building efficiency programs. Initially focusing on the largest buildings or largest emitters allows a program to capture the bulk of the relevant emissions or energy consumption while lowering the administrative burden. Because BPS programs have a small geographic scope, leakage is a risk: the highest emitters, notably data centers and industrial sites, would have an incentive to exit the city if compliance costs become significant. This risk can be mitigated with tailored baselines, special allocation provisions, or a broader geographic scope—all strategies that have been used in carbon markets.

Understanding how trading of compliance obligations affects building owners’ retrofit decisions, compliance costs, and savings opportunities requires knowledge of the building sector’s abatement options and costs. Including tradable markets in a BPS design increases compliance flexibility, both across entities and across time when allowance banking is permitted. However, for a market to work effectively, building owners must have a clear understanding of the cost and the energy or emissions savings of various retrofit packages for their properties. The benefits of trading within a corporate bubble versus across all covered entities is difficult to gauge without an indepth understanding of the ownership structure of the city’s covered building stock.

BPS policies target both electricity and energy consumption and thus interact with other environmental programs. These interactions can take different forms, which are not always intuitive:

• The environmental benefits can be additive. For example, the New York City BPS should create demand for local renewable energy that is supplemental to the state’s Clean Energy Standard since New York State RECs can be sold only to compliance entities.

• Program-related emissions reductions could be offsetting. That might be the case with RGGI if emissions reductions tied to a BPS reduce the compliance burden for RGGI generators but not the RGGI cap.

• Buildings might be subject to conflicting measures if, for example, the state RPS drives emissions reductions that are not fully factored into a city BPS program’s algorithms used to calculate emissions, or if electric car charging stations increase electricity consumption covered by the program.

Although that list reveals potential policy and market interactions with BPS policies, further quantitative analysis is required to understand the magnitude of these interactions and their effects on emissions. As they develop future policies and modify current designs, municipal officials should recognize these interactions and adapt policy designs as necessary to counter or limit adverse consequences.

...

Scope

The first carbon market design question is, Which entities should be covered? The answer must balance two goals: capturing as much of the sector’s emissions as possible while keeping the number of compliance entities reasonable. Carbon markets therefore do not cover individual homes or vehicles but set the point of compliance at the power plant, refinery, or point of fuel distribution. BPS program designers must choose whether to regulate entities based on their size or based on their consumption or emissions level.

...

Price Formation

Regulatory programs entail compliance costs that can be expressed as cost per unit of emissions or energy consumption reduced. These compliance costs are reasonably transparent in tradable programs, which have transactable prices, and they are implicit in nontrading programs. This section uses a very simple conceptual model to illustrate price formation and trading dynamics in BPS programs.

Our hypothetical program targets energy reductions, which can be translated into carbon reductions. It has five buildings and two owners. All buildings face a 10 percent reduction target in the first phase of compliance. Each building has three abatement options: a lighting retrofit, the addition of window films, and an HVAC retrofit; not all options are available to all buildings (Table 3).

In reality, buildings have many options to reduce consumption and emissions. The Department of Energy’s Scout16 building efficiency software has close to 30 built-in commercial energy efficiency measures. The Tokyo program lists 20 distinct measures that span demand-side management and operational measures, appliance and lighting efficiency, heating and cooling systems, software, and sensors. Organized from lowest to highest cost per unit of avoided consumption or cost per unit of avoided emissions, these measures form the buildings’ marginal abatement cost (MAC) curve. In our conceptual example, lighting retrofits cost $0.90 per square foot for an assumed 12 percent reduction in building consumption. Using average office building consumption data, this represents a cost of $0.10 per Btu reduced: it is the most cost-effective option. Window film abatement costs are $0.13 per Btu, and HVAC upgrades’ cost-effectiveness is $0.44 per Btu. Our example builds an abatement cost curve in units of dollars per thousand Btu reduced; however, it could also be translated into dollars per ton of greenhouse gas reduced, given information on emissions rates and time of use for various energy forms, electricity in particular. The MAC curve is built by aggregating the effectiveness of the available measures over the building stock (Figure 1). For the five buildings at hand, the three measures can reduce consumption by almost 2 mmBtu, which represents 30.2 percent of the total consumption.