CO2 Emissions In Power Sector Research Articles

Role of Environmental Policy Stringency on Sectoral CO2 Emissions in EU-5 Countries: Disaggregated Level Evidence by Novel Quantile-Based Approaches

Consistent with the increasing awareness of environmental problems, countries have applied various measures to combat climate change by preventing environmental degradation of the environment. In this context, a set of measures in different areas and sectors have been taken. Although it is possible to consider each of them, instead, using a more comprehensive index, such as the Environmental Policy Stringency Index, can be appropriate in examining the effects of environmental measures in curbing emissions. Accordingly, this research examines the effect of Environmental Policy Stringency Index on sectoral carbon dioxide (CO2) emissions in the European Union Five countries (namely, Germany, Spain, France, United Kingdom, and Italy) by using data for the period 1990/Q2-2020/Q4, performing novel quantile-based approaches. The outcomes show that at higher quantiles, Environmental Policy Stringency Index provides (a) a decrease in building sector CO2 emissions in France, the United Kingdom, and Italy; (b) a decline in industrial combustion sector CO2 emissions in France and Italy; (c) a curb power sector CO2 emissions in Germany, Spain, and France; (d) a decrease in transport sector CO2 emission in Germany and France; (e) there are causalities from Environmental Policy Stringency Index to sectoral CO2 emissions across quantiles except for some ones; (f) the outcomes are verified as robust. The outcomes prove the differentiating effects of Environmental Policy Stringency Index across sectors under the empirical examinations, quantiles, and countries. Thus, the study discusses various policy endeavors, such as consideration of the varying structure of environmental measures, application of nonlinear approaches, and focusing on some sectors to go fast in curbing sectoral CO2 emissions.

Carbon emissions impacts of operational network constraints: The case of Spain during the Covid-19 crisis

Operating a highly decarbonized power system is technically complex and introduces novel challenges for system operators. To this effect, the hourly day-ahead market schedule must be compliant with all the network security criteria. If required, specific generators should be curtailed or started up after the market clearing via so-called redispatching actions. In this paper, we analyze the bias in emissions intensity of electricity generation that result from not internalizing grid operational limitations in the day-ahead market clearing. In other words, we investigate the incremental emissions resulting from actions by system operators to make the day-ahead market schedule physically feasible. We use hourly data from the Spanish power system between 2019 and 2021. We estimate that while redispatching actions accounts for 2–4% of total annual electricity demand, they represent 6–11% of the annual power sector's CO2 emissions. We find that volumes of fossil generators started up for network security reasons by system operators increase in hours during which the share of renewables in the supply mix is relatively high but, additionally, show that volumes also significantly increase during hours with low energy demand, as during the Covid-19 crisis. These latter actions are not triggered to alleviate grid bottlenecks, but to solve location-specific operational constraints requiring a minimum volume of synchronous generators always running. Because of these actions, we estimate that the emissions from the day-ahead market schedule are downward biased between +0.00391 and + 0.0145 tn of CO2 for each additional MWh of scheduled wind or photovoltaics. We offer several recommendations to better align the day-ahead schedule with the grid operation needs leading to a reduced need for redispatching actions.

Subsidy removal, regional trade and CO2 mitigation in the electricity sector in the Middle East and North Africa region

This study analyzes the impacts on the power sector in the Middle East and North Africa region of three policies: removal of fuel subsidies, enhanced cross-border electricity trade, and a cap on carbon dioxide emissions. The analysis uses a power system planning model that minimizes the total electricity supply cost over 2018–2035 by satisfying specified technical, economic, environmental, and policy constraints. The study shows that the region would save between US$26.3 billion and US$27.5 billion, measured in 2018 prices, by removing subsidies to natural gas used for power generation. Cross-border electricity trade would save US$83.6 billion to US$90.9 billion. The two policies together would yield a reduction of 10 percent in cumulative power-sector CO2 emissions in the region, with a net cost savings of US$111 billion. If a carbon emission-constraining policy is considered to achieve the same level of emissions reduction, the power supply costs will increase by US$97 billion. The study also reveals that the removal of fossil fuel subsidies and expanded cross-border electricity trade significantly complement each other and also to achieve climate change mitigation targets in the MENA region.

Exploration of CO2 emission reduction pathways: identification of influencing factors of CO2 emission and CO2 emission reduction potential of power industry.

The online version contains supplementary material available at 10.1007/s10098-022-02456-1.

The implicit cost of carbon abatement during the COVID-19 pandemic

This paper provides novel estimates of the implicit cost of carbon abatement associated with the COVID-19 crisis. We compare that to the costs from renewable investments that would lead to similar abatement. Focusing on the Spanish economy and its power sector, we combine machine learning and simulation tools to construct a precise counterfactual of market performance in absence of the crisis. Results suggest that power sector CO2 emissions fell by 4.13 Million Tons (about 11.5%) during 2020 due to the pandemic, less than half of the actual year-on-year emissions reductions. Investing in renewables to achieve similar carbon abatement would yield an implicit cost of 60–65 Euro/Ton of CO2. Conversely, the pandemic caused a substantial GDP loss in Spain, relative to the extent of overall carbon abatement. The resulting cost of carbon abatement associated with the pandemic thus exceeded 7 thousand Euro/Ton.

The U.S. power sector emissions of CO2 and NOx during 2020: Separating the impact of the COVID-19 lockdowns from the weather and decreasing coal in fuel-mix profile

In recent years, the United States power sector emissions of CO2 and NOx have decreased due to declining coal and increasing natural gas and renewables in the fuel-mix. In April 2020, the COVID-19 social restrictions in the United States led to a decline in electricity demand from the commercial and industrial sectors. In this study, we estimate the changes in the emissions of CO2 and NOx from the U.S. power sector due to three factors: 1) weather, 2) the fuel-mix change in the past five years, and 3) the COVID-19 social restrictions. We use a multivariate adaptive regression splines (MARS) model to separate the impacts of outdoor temperature and type-of-day from the COVID-19 on power generation, and the daily operation status of 3013 power units to account for the fuel-mix change. We find that electricity demand changes due to COVID occurred mostly from March to June 2020, with electricity demand generally returning to 2015–2019 levels starting in July 2020. We find the U.S. power sector CO2 emissions, reported by EPA, dropped by 29.8 MTCO2 (−26%) in April 2020, relative to the average April emissions between 2015 and 2019. Of that reduction, we attribute declines of 18.3 ± 4.0 MTCO2 (−18 ± 4%) to the COVID-19 lockdowns, declines of 13.7 ± 4.2 MTCO2 (−12 ± 4%) to a fuel-mix change, and increases of 2.3 ± 1.1 MTCO2 (+2 ± 1%) due to weather variability compared to the five prior years. For the same month, the power sector NOx emissions dropped by 27.6 thousand metric tons (−42%) in April 2020, relative to the past five-year monthly average. Of that reduction, we attribute declines of 10.5 ± 2.4 thousand metric tons (−22 ± 5%) to the COVID-19 lockdowns, declines of 18.5 ± 2.5 thousand metric tons (−28 ± 4%) to a fuel-mix change, and increases of 1.4 ± 0.6 thousand metric tons (+2 ± 1%) due to weather variability. This result highlights the importance of accounting for weather and fuel-mix changes when estimating the impact of COVID-19 on the power sector emissions.

The Expanding Coal Power Fleet in Southeast Asia: Implications for Future CO2 Emissions and Electricity Generation

AbstractCoal combustion for power generation made up 30% of global CO2 emissions in 2018. To achieve the goal of the Paris Agreement to keep global average temperatures below 2°C, power generation must be decarbonized globally by mid‐century. This requires a rapid phase‐out of coal‐fired power generation. However, global coal power expansion continues, mostly in developing countries where electricity demand continues to increase. Since the early 2010s, Southeast Asia's coal power capacity expansion has been among the fastest in the world, following China and India, but its implications for the global climate and regional energy transition remain understudied. Here we examine Southeast Asia's power generation pipeline as of mid‐2020 and evaluate its implications for the region's CO2 emissions over the plant lifetime as well as projected electricity generation between 2020‐2030 in Indonesia, Vietnam, and the Philippines. We find that power plants under construction and planned in Southeast Asia as of 2020 will more than double the region's fossil fuel power generation capacity. If all fossil fuel plants under development are built, Southeast Asia's power sector CO2 emissions will increase by 72% from 2020 to 2030 and long‐term committed emissions will double. Moreover, in Indonesia, Vietnam, and the Philippines, projected electricity generation from fossil fuel plants under development, combined with generation from renewable capacity targets and existing power capacity, will exceed future national electricity demand. As a result, fossil fuel plants will likely be underutilized and/or become stranded assets while also potentially crowding out renewable energy deployment.

Air quality-related health co-benefits from Pennsylvania’s entry into the Regional Greenhouse Gas Initiative (RGGI)

BACKGROUND AND AIM: Climate policies can provide local health co-benefits by simultaneously reducing local and regional air pollutants co-released with greenhouse gas emissions. The Regional Greenhouse Gas Initiative (RGGI) is a regional cap and trade system that seeks to reduce CO₂ emissions from the electric power sector in eleven northeastern and mid-Atlantic states in the United States. Here we focus on Pennsylvania’s anticipated entry into RGGI in 2022. As a major power producer and carbon-emitter in the PJM interconnection (i.e., the Regional Transmission Organization that manages the wholesale electricity market in Pennsylvania and twelve other states), Pennsylvania’s participation affects both the PJM electricity market and the RGGI carbon market. METHODS: By combining a power system model of PJM with a reduced form model of CO₂ emissions abatement from RGGI states that are not in PJM, we first simulate the effects of Pennsylvania’s participation in RGGI on electricity market outcomes, CO₂ emissions, and other local and regional air pollutants. We then use a range of marginal damage estimates derived from reduced-form air pollution models to monetize air quality-related health impacts. RESULTS:Comparing the scenarios with and without Pennsylvania’s participation in RGGI, we find the annual average power sector CO₂ emissions in Pennsylvania to be 40% lower from 2022 to 2030. During the same time period, the annual emissions are 79%, 68% and 76% lower for SO₂, NOx and PM2.5 emissions, respectively. Such a reduction in co-emitted air pollutants leads to cumulative health co-benefits of $17.7 billion to $40.8 billion. However, the reduced emissions and health damages in Pennsylvania are slightly offset by increases in the other states in PJM that do not participate in RGGI. CONCLUSIONS:Our study highlights the large potential for health co-benefits from Pennsylvania’s entry into RGGI, though the cross-state leakage issue requires careful consideration in the policy design and implementation process. KEYWORDS: Air pollution, climate, health co-benefits, policy

No COVID-19 climate silver lining in the US power sector

Recent studies conclude that the global coronavirus (COVID-19) pandemic decreased power sector CO2 emissions globally and in the United States. In this paper, we analyze the statistical significance of CO2 emissions reductions in the U.S. power sector from March through December 2020. We use Gaussian process (GP) regression to assess whether CO2 emissions reductions would have occurred with reasonable probability in the absence of COVID-19 considering uncertainty due to factors unrelated to the pandemic and adjusting for weather, seasonality, and recent emissions trends. We find that monthly CO2 emissions reductions are only statistically significant in April and May 2020 considering hypothesis tests at 5% significance levels. Separately, we consider the potential impact of COVID-19 on coal-fired power plant retirements through 2022. We find that only a small percentage of U.S. coal power plants are at risk of retirement due to a possible COVID-19-related sustained reduction in electricity demand and prices. We observe and anticipate a return to pre-COVID-19 CO2 emissions in the U.S. power sector.

The U.S. Gas Pipeline Transportation Market: An Introductory Guide with Research Questions for the Energy Transition

Natural gas currently represents close to a third of U.S. primary energy consumption and has often been described as a bridge fuel in the context of the ongoing energy transition. As coal plants are retired and the share of variable renewable resources in the U.S. power markets grows, power sector CO2 emissions are declining and gas-fired power plants increasingly relied upon to provide peak and balancing services to complement the variable electricity supply from wind and solar plants. Growth in gas-fired electricity generation in the past decade has made the power sector the largest user of the U.S. interstate gas pipeline network, just ahead of the industrial and building sectors. Nevertheless, future gas demand from these latter two sectors, and from the power sector, is expected to be reduced by policy and regulatory initiatives aimed at electrification of heating loads and economy-wide decarbonization. These developments open up important questions around the role of the U.S. interstate pipeline network in the ongoing energy transition. Such questions include what changes may be needed in the gas transportation markets to provide more flexible gas delivery services to gas-fired generators that provide valuable balancing in the power markets, and how long-term stranded asset risk for gas transportation infrastructure should be managed in the face of electrification and decarbonization. The objective of this paper is to facilitate further research to address these types of questions by outlining the main market features and regulations important for understanding the U.S. gas transportation market.

COVID-19-induced low power demand and market forces starkly reduce CO2 emissions

The COVID-19 pandemic continues to strongly affect global energy systems. Global power sector CO2 emissions have shown a substantial decline, thanks to (a) the COVID-19-induced economic downturn and resulting reduction of electricity demand and (b) a decrease of carbon intensity of power generation as coal generation is decreased most strongly. These effects illustrate the opportunity for different policies to support a structural and accelerating decline of power sector emissions. The societal response to the pandemic has reduced global power demand, disproportionally affecting coal power generation and thus leading to a strong CO2 emissions decline. Policy should apply 2020’s lessons to ensure that power sector emissions have peaked in 2018 and go into structural decline.

The prospective impacts of 2019 state energy policies on the U.S. electricity system

Over the past several years state energy policies have been evolving rapidly, and are more frequently including higher targets, including 100% clean energy targets. This study assesses the aggregate impacts of state clean energy standards and emissions policies on national electricity generation, power sector carbon dioxide (CO2) emissions, and electricity prices and system costs. To do so, we apply the Regional Energy Deployment System (ReEDS) model, which is a detailed electric sector capacity expansion model, to evaluate scenarios with and without state policies and using a range of renewable energy technology cost projections. Across the scenarios analyzed, we find that the state policies drive 1.9%–10.7% of total nationwide clean energy and reduce cumulative power sector CO2 emissions by 2.6%–5.4% over the 2020–2050 study period. This incremental generation is predominantly, but not exclusively, from renewable energy technologies. In most cases, the state policies result in increases to electricity prices and electricity system costs, and policy costs are sensitive to the future cost of clean energy technologies. Across all scenarios, the levelized cost of incremental policy-driven clean energy generation is estimated to be $17–38/MWh and the average cost of CO2 abatement from the state-level policies is estimated to be $29–74/metric ton.

Turning the corner on US power sector CO2 emissions—a 1990–2015 state level analysis

Total CO2 emissions from the United States power sector increased over the period 1990–2005, but peaked soon after, and by 2015 they had declined by 20% compared to 2005. This study analyzes the supply-side drivers of the increasing trend up until 2005 as well as the factors across US states that enabled significant reductions in the following decade. Using index decomposition analysis, we show that the two main factors driving the CO2 decrease were natural gas substituting for coal and petroleum, and large increases in renewable energy generation (primarily wind)—which were responsible for 60% and 30% of the decline respectively since 2005. Both effects were concentrated in states where low natural gas prices or a combination of federal tax credits, state energy policies, decreasing costs of renewables, and advantageous wind conditions drove significant reductions of CO2 emissions—resulting in the overall national emissions decline.

The Affordable Clean Energy rule and the impact of emissions rebound on carbon dioxide and criteria air pollutant emissions

The Affordable Clean Energy (ACE) rule, the US Environmental Protection Agency’s (EPA) proposed replacement of the Clean Power Plan (CPP), targets heat rate improvements (HRIs) at individual coal plants in the US. Due to greater plant efficiency, such HRIs could lead to increased generation and emissions, known as an emissions rebound effect. The EPA Regulatory Impact Analysis for the ACE and other analyses to date have not quantified the magnitude and extent of an emissions rebound. We analyze the estimated emissions rebound of carbon dioxide (CO2) and criteria pollutants sulfur dioxide (SO2) and nitrogen oxides (NOX), using results from the EPA’s power sector model, under the ACE in 2030 at model coal plants and at the state and national levels compared to both no policy and the CPP. We decompose emissions changes under a central illustrative ACE scenario and find evidence of a state-level rebound effect. Although the ACE reduces the emissions intensity of coal plants, it is expected to increase the number of operating coal plants and amount of coal-fired electricity generation, with 28% of model plants showing higher CO2 emissions in 2030 compared to no policy. As a result, the ACE only modestly reduces national power sector CO2 emissions and increases CO2 emissions by up to 8.7% in 18 states plus the District of Columbia in 2030 compared to no policy. We also find that the ACE increases SO2 and NOX emissions in 19 states and 20 states plus DC, respectively, in 2030 compared to no policy, with implications for air quality and public health. We compare our findings to other model years, additional EPA ACE scenarios, and other modeling results for similar policies, finding similar outcomes. Our results demonstrate the importance of considering the emissions rebound effect and its effect on sub-national emissions outcomes in evaluating the ACE and similar policies targeting HRIs.

The impact of a feed-in tariff on wind power development in Germany

We estimate the impact of a feed-in tariff (FIT) on wind power investment and emission reductions in Germany from 1996–2010. We find that a 1 €-cent/kWh increase in the FIT rate would increase additions to capacity by 796 MW on average per year from 1996–2010. In addition, we find that proximity to existing transmission lines became less of a consideration in determining the location of new wind power plants, after a Renewable Energy Law (EEG) provision shifted the cost of transmission system upgrades from wind power developers to grid operators. The lack of a signal on scarcity of transmission capacity may have contributed to a distribution of wind power plants that makes suboptimal use of existing infrastructure, necessitating investment in new transmission corridors. In 2000, the EEG also replaced the uniform feed-in tariff with one linked to wind power potential, such that more windy locations received a lower incentive per unit of output, in order to contain costs and spread investment across the country. We compare the wind-dependent EEG incentive with a counterfactual scenario, in which a uniform incentive is offered, and find that the EEG is slightly more cost-effective, achieving about 4% greater reductions in power sector CO2, SOx, NOx, and PM10 emissions.

Driving forces of provincial-level CO2 emissions in China’s power sector based on LMDI method

As the major energy consumer and carbon emitter, the power sector accounts for 40% of total carbon emissions in China in 2011. Understanding provincial-level driving mechanisms of CO2 emissions in power sector is vital for achieving China’s national carbon emissions reduction targets in 2030. To understand the critical provinces and driving forces of CO2 emissions in power sector, this paper firstly derives seven different driving factors based on the logarithmic mean Divisia index (LMDI) decomposition model. The provincial-level CO2 emissions in thermal power sectors are calculated from 2004 to 2014. Then, we analyze the CO2 emissions growth ratio of each province, provincial-level change rate of contribution and positive or negative contributions of the emission dynamics for each driving force. The main results show that the power sector of Inner Mongolia and Jiangsu contribute a lot to national CO2 emissions. The change of CO2 emissions of power sector is bigger in developing provinces compared to that in developed provinces. Based on provincial the CO2 emissions changes and total amounts, more carbon emission reduction policy should be implanted in Inner Mongolia, Xinjiang, Anhui, Jiangsu and Ningxia. In addition, the economic scale, industrial intensity and energy intensity are the critical driving forces for total carbon emission. By investigating the critical driving forces and their contributions in critical provinces, this paper aims to provide theoretical foundations for decarbonizing power sector.

Response of electricity sector air pollution emissions to drought conditions in the western United States

Water is needed for hydroelectric generation and to cool thermoelectric power plants. This dependence on water makes electricity generation vulnerable to droughts. Furthermore, because power sector CO2 emissions amount to approximately one third of total US emissions, droughts could influence the inter-annual variability of state- and national-scale emissions. However, the magnitude of drought-induced changes in power sector emissions is not well understood, especially in the context of climate mitigation policies. Using multivariate linear regressions, we find that droughts are positively correlated to increases in electricity generation from natural gas in California, Idaho, Oregon, and Washington; and from coal in Colorado, Montana, Oregon, Utah, Washington, and Wyoming. Using a statistical model, we estimate that this shift in generation sources led to total increases in regional emissions of 100 Mt of CO2, 45 kt of SO2, and 57 kt of NOx from 2001 to 2015, most of which originated in California, Oregon, Washington, and Wyoming. The CO2 emissions induced by droughts in California, Idaho, Oregon, and Washington amounted to 7%–12% of the total CO2 emissions from their respective power sectors, and the yearly rates were 8%–15% of their respective 2030 yearly targets outlined in the Clean Power Plan (CPP). Although there is uncertainty surrounding the CPP, its targets provide appropriate reference points for climate mitigation goals for the power sector. Given the global importance of hydroelectric and thermoelectric power, our results represent a critical step in quantifying the impact of drought on pollutant emissions from the power sector—and thus on mitigation targets—in other regions of the world.

Carbon Pricing and Cross-Border Electricity Trading for Climate Change Mitigation in South Asia

South Asia's electricity supply system is quite carbon-intensive, particularly due to extensive use of coal. Under business as usual, that situation is expected to continue for several decades. Using an electricity system planning model, this study investigates two complementary strategies to reduce CO2 emission intensity of the power sector in South Asia: carbon pricing, and expansion of cross-border electricity trade to exploit clean energy resources, especially hydropower. The study finds that with a carbon tax imposed on fossil fuels used for power generation, CO2 emissions from the power sector would be 10% lower than that in the baseline over 20152040 even if the cross-border electricity transmission capacity is not expanded from the current level. On the other hand, if the cross-border transmission capacity is expanded to facilitate unlimited power trading across countries, the carbon tax would cause 16% reduction of regional power sector CO2 emissions from the baseline. The regional electricity trade is not only beneficial economically as it saves almost US$100 billion electricity supply cost in the region over 20152040, but also an attractive option for climate change mitigation. The carbon tax would, however, increase the power supply cost and could adversely impact consumers unless the carbon tax revenue is used as a safeguard measure.

Polarization of CO2 emissions in China's electricity sector: Production versus consumption perspectives

Abstract The inter-provincial inequality of per capita CO2 emissions in China's electricity sector means that their responsibilities for CO2 emission reduction are different. Considering the spatial separation of CO2 emissions in power production and consumption, with respect to the large scale inter-provincial electricity trade in China, this paper innovatively investigates the sub-national inequality and polarization degree of per capita CO2 emissions in China's electric power sector from the perspectives of both production and consumption. The overall tendencies of the sub-national polarization degrees of per capita CO2 emissions embodied in the both electric power consumption and production in China show an increasing trend. The results indicate that the polarization distribution of per capita CO2 emissions is still one of the important factors leading to difficulties in achieving the new reduction arrangements. The evolution of the bi-polarization analysis shows that the grouping results of per capita CO2 emissions are different from production and consumption perspectives, as well as the high- and low-emission groups have significantly different characteristics. The inequality and polarization degree of per capita CO2 emissions in China's electric power sector have changed as the CO2 emissions embodied in the electricity trade had been taken into account. One-Size-Fits-All Strategies are unlikely to be successful in advancing the provincial cooperation on CO2 emissions reduction.

Social cost of carbon pricing of power sector CO2: accounting for leakage and other social implications from subnational policies

In environments where climate policy has partial coverage or unequal participation, carbon dioxide (CO2) emissions or economic activity may shift to locations and sectors where emissions are unregulated. This is referred to as leakage. Leakage can offset or augment emissions reductions associated with a policy, which has important environmental and economic implications. Although leakage has been studied at national levels, analysis of leakage for subnational policies is limited. This is despite greater market integration and many existing state and regional environmental regulations in the US. This study explores leakage potential, net emissions changes, and other social implications in the US energy system with regionally differentiated pricing of power sector CO2 emissions. We undertake an economic analysis using EPRI’s US-REGEN model, where power sector CO2 emissions are priced in individual US regions with a range of social cost of carbon (SCC) values. SCC estimates are being considered by policy-makers for valuing potential societal damages from CO2 emissions. In this study, we evaluate the emissions implications within the SCC pricing region, within the power sector outside the SCC region, and outside the power sector (i.e. in the rest of the energy system). Results indicate that CO2 leakage is possible within and outside the electric sector, ranging from negative 70% to over 80% in our scenarios, with primarily positive leakage outcomes. Typically ignored in policy analysis, leakage would affect CO2 reduction benefits. We also observe other potential societal effects within and across regions, such as higher electricity prices, changes in power sector investments, and overall consumption losses. Efforts to reduce leakage, such as constraining power imports into the SCC pricing region likely reduce leakage, but could also result in lower net emissions reductions, as well as larger price increases. Thus, it is important to look beyond leakage and consider a broader set of environmental and economic metrics. Leakage rates, net emissions outcomes, electricity price changes, fuel market effects, and macroeconomic costs vary by region of the country, time, policy stringency, policy design (e.g. leakage mitigation provisions), policy environment in neighboring regions, and price responsiveness of demand.