EIA Analyzes Power Sector Emissions Factors

Source: U.S. Energy Information Administration, Monthly Energy Review, September 2013, and the Annual Energy Outlook 2014
Note: GHG is greenhouse gases. The GHG10 case assumes a $10 per metric ton fee on CO₂ emissions, beginning in the year 2015. The GHG25 assumes a $25 per metric ton fee on CO₂ emissions beginning in 2015. Both cases escalate the CO₂ fee at a rate of 5% per year. The GHG10 case with low natural gas prices combines the assumptions of the GHG10 case with the High Oil and Gas Resource case, which results in lower gas prices and encourages greater natural gas use.

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In 2012, almost 40% of total energy-related CO₂ emissions resulted from electricity generation. About three-fourths of those power sector emissions occurred from burning coal, the most carbon-intensive fuel. Policies to reduce CO₂ emissions could result in less consumption of coal in favor of natural gas, which emits about 40% as much CO₂ per kilowatthour as typical coal-fired generation when used in a combined-cycle plant, as well as increases in other low- or zero-carbon power generating technologies such as renewables and nuclear.

Earlier this week, the Environmental Protection Agency (EPA) issued a proposed rule  that would require reductions in CO₂ emissions from existing fossil-fueled electric power plants. The EPA proposal includes emission rate targets for each state, measured as pounds of CO₂ emissions per megawatthour of covered generation, as well as guidelines for the development, submission, and implementation of state plans. The emission rate targets vary significantly across individual states, reflecting the application of a series of common building blocks to states with widely different starting points in their respective electricity markets.

The Annual Energy Outlook 2014 (AEO2014) Reference case, which assumes current laws and regulations, does not include the EPA proposal. Currently there are two regional programs in the Northeast and California (the Regional Greenhouse Gas Initiative and Assembly Bill 32, known as RGGI and AB32, respectively) that include control policies for greenhouse gases (GHGs) from the power industry, which are also included in the AEO2014 Reference case. All existing final environmental rules, including the Mercury and Air Toxics Standard, are also included in the projections. After taking these existing environmental regulations into account, the projections for electricity generation and its resulting emissions are primarily determined by the relative operating costs of the different technologies. The AEO2014 Reference case projections show several CO₂-related trends, including:

• CO₂ emissions from the electric power sector increase from 2,035 million metric tons in 2012 to 2,271 million metric tons in 2040, an increase of 12%
• The share of power sector CO₂ emissions from natural gas increases from 24% to 27%, as natural gas-fired plants account for most of the capacity that is added to meet increases in demand and to replace retiring plants
• Few new coal plants are added, as uncertainty about future carbon regulations influences capacity decisions

While EIA does not assume the final structure of any proposed regulations, in order to represent policies that explicitly or implicitly place a value on GHG emissions, the AEO2014 includes alternative cases that impose a fee on energy-related CO₂ emissions. These side cases incorporate an initial CO₂ value of $10 (GHG10 case) and $25 (GHG25 case) per metric ton in 2015, rising by 5% per year. The GHG10 case is also combined with High Oil and Gas Resources, which results in lower gas prices and encourages greater natural gas use. In these side cases, EIA projects the following results as compared with the AEO2014 Reference case:

• 2025 power sector CO₂ emissions are 16% and 49% lower in the GHG10 and GHG25 cases with fees, respectively, and 23% lower when the GHG10 case is combined with the High Oil and Gas Resource case
• 2040 power sector CO₂ emissions reductions range from 36% to 82% across the three side cases, which is greater than the corresponding changes in other sectors and indicates that the electric power industry is typically the most cost effective sector to achieve reductions in response to economy-wide CO₂fees
• Natural gas-fired generation increases sharply beginning when CO₂ fees are assumed to be introduced in 2015, followed by more nuclear and renewable plant additions as the fees increase
• Natural gas-fired generation levels off around 2030 in the GHG10 case, and it begins to decline after 2025 in the GHG25 case
• In the High Oil and Gas Resource case without CO₂ fees, lower natural gas prices result in higher gas-fired generation and CO₂ emissions in the power sector as more new natural gas plants are built instead of nuclear and renewable capacity
• Natural gas-fired generation continues to increase through 2040 when the fees for the GHG10 case are combined with the lower gas prices from the High Oil and Gas Resource case

Source: U.S. Energy Information Administration, Monthly Energy Review, September 2013, and the Annual Energy Outlook 2014

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Additional analysis can be found in the AEO2014 Market Trends discussion of emissions from energy use.

EIA Updates U.S. Emissions Trends

Source: U.S. Energy Information Administration, State Energy Data System (SEDS) 2014

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U.S. energy-related carbon dioxide (CO₂) emissions in 2013 were 10% below the benchmark year of 2005. Emissions in 2013 were roughly 2% above their 2012 level and 1.5% below their 2011 level, when emissions were 8.6% below the 2005 level. Recently released state-level data through 2011, calculated from the State Energy Data System (SEDS) and aggregated here by Census regions, show different parts of the country generally experiencing this downward trend, but at variable rates by region.

Between 2005 and 2011, all four Census regions—West, South, Midwest, and Northeast—experienced emissions declines, with the Northeast experiencing larger emissions reductions than the other regions. Underlying state-level emissions changes spanned an even wider range, from a 20% emissions increase in Nebraska (Midwest) to a 33% decrease in Nevada (West). Regional and subregional spreads reflect differences in local energy economics, population distribution, and other factors.

Source: U.S. Energy Information Administration, State Energy Data System (SEDS) 2014

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Drivers of faster, larger emissions declines in the Northeast include extensive urbanization, translating into denser, more energy-efficient population centers, and increasingly low-carbon electricity generation from natural gas, nuclear, and renewables, instead of coal. The Northeast includes the top-three lowest emitting states per unit of economic output (New York, Connecticut, and Massachusetts) and two of the top-five states with the cleanest electricity sources (Vermont and New Hampshire).

Compared to the Northeast, the other regions (Midwest, West, and South) have more diverse state-level characteristics, which contributed to relatively slower net emissions declines. Steep emissions reductions in some states were partially offset by escalating emissions elsewhere. For example, states like Wyoming (West), North Dakota (Midwest), and West Virginia (South) have more carbon-intensive energy production, higher and less efficient energy use in more sparsely populated areas, and heavily coal-reliant electricity generation compared to other states in those regions. Since 2009, factors driving the uptick in Nebraska's emissions profile included marked expansion of the biofuels (corn-based ethanol) industry, as well as increased production of crude oil and the temporary closure of the Fort Calhoun nuclear power plant. Conversely, Nevada's lower-bounding trend shows the effects of substantially decarbonizing its electric power sector—between 2005 and 2011, Nevada significantly reduced its coal use, while increasing solar and geothermal use.

Earlier this week, the Environmental Protection Agency (EPA) issued a proposed rule that would require reductions in carbon dioxide emissions from existing fossil-fueled electric power plants. The EPA proposal includes emission rate targets for each state, measured as pounds of carbon dioxide emissions per megawatthour of covered generation, as well as guidelines for the development, submission, and implementation of state plans. The emission rate targets vary significantly across individual states, reflecting the application of a series of common building blocks to states with widely different starting points in their respective electricity markets.

Source: EIA

Effect of Power Plant Closures on CO2 Emissions

Source: U.S. Energy Information Administration, Annual Energy Outlook 2014, Issues in Focus

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Significant retirements of nuclear and coal power plants in the United States could change the amount of carbon dioxide (CO₂) emitted by the electric power sector. EIA's Annual Energy Outlook 2014 (AEO2014) features several accelerated retirements cases that represent conditions leading to additional coal and nuclear plant retirements in order to examine the potential energy market and emissions effects of the loss of this capacity. CO₂ emissions are significantly reduced when compared to the Reference case in side cases with accelerated coal retirements. CO₂ emissions increase slightly in the Accelerated Nuclear Retirements case. Natural gas and renewables are the primary replacements for lost capacity in each scenario.

Source: EIA

EIA Releases 2013 U.S. CO2 Emissions Estimate

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2014

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Once all data are in, energy-related carbon dioxide (CO₂) emissions in 2013 are expected to be roughly 2% above the 2012 level, largely because of a small increase in coal consumption in the electric power sector. Coal has regained some market share from natural gas since a low in April 2012; however the impact on overall emissions trends remains fairly small.

Emissions in 2013 are slightly more than 10% below 2005 levels, a significant contribution towards the goal of a 17% reduction in emissions from the 2005 level by 2020 that was adopted by the current Administration. This level of reduction is expected to continue through 2015, according to EIA's most recent Short-Term Energy Outlook.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2014

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CO₂ emissions from energy activities declined four out of six years since their 2007 peak, and were historically low (12% below the 2005 level) in 2012. From 2005 to 2013, the key energy-economic drivers of a changing U.S. energy landscape included:

• Weak economic growth in recent years, dampening growth in energy demand compared to pre-recession expectations
• Continuously improving energy efficiency across the economy, including buildings and transportation
• High energy prices over the past four years, with the exception of natural gas, since about 2010
• An abundant and inexpensive supply of natural gas, resulting from the widespread use of new production technologies for shale gas
• Power sector decarbonization since 2010, as natural gas and renewables displaced coal

Source: EIA

Alberta's CCEMC Releases Annual Report

EDMONTON – The Alberta-based Climate Change and Emissions Management (CCEMC) Corporation released its 2012/2013 annual report that features 12 new renewable energy and energy efficiency projects. In total, the CCEMC now supports 51 clean tech projects with $212.8 million in committed funding. More

Illinois CCS Update

In an update on its carbon capture project at an ethanol plant near Decatur, Illinois, Archer Daniels Midland Co. says it has captured 685,000 metric tons of carbon emissions and stored them underground storage in the past two years. Carbon dioxide injections began in November 2011 at a rate of about 1,000 tons a month and are expected to continue through next year when the project is expected to reach the permitted level of 1 million tones. 

The project at the Decatur plant is among the largest CCS experiments in the country. The purpose is to test the storage potential of the Mount Simon Sandstone and the integrity of the overlying sealant rocks. Decatur was initially selected in October 2009 for the DOE Phase 1 research and development grants. Following successful completion of the Phase 1 activities, it was identified as one of the most promising industrial CCS projects through a competitive process and entered into Phase 2 with additional funding to begin design, construction, and operation.

Drilling began in February 2009 and a successful injection with a rate of 1000 tons per day was achieved in September 2009. 3D seismic surveys of the injection zone were completed in March 2010 in preparation for Phase 2.

Construction activities began at Decatur on August 26, 2011 with injection commencing in November 2011. As of April 2012, the project has successfully stored over 110,000 tons of CO2. In September 2012, the DOE marked 2 major milestones for the Decatur CCS project: The construction on the project’s storage facility, as well as the public opening of the National Sequestration Education Center. In November 2012 Decatur project completed its first year of CO2 injection operations with a total of 317,000 tons having been buried at a rate of 1,100 tons/day.

The target formation, the Mount Simon Sandstone, was selected as the optimum saline sink because of its widespread nature and immediately overlying Eau Claire shale seal. The Mount Simon Sandstone also underlies one of the largest concentrations of coal fired power plants in the world. This makes the Mount Simon Sandstone one of the most significant carbon storage resources in the United States.

Archer Daniels Midland (June 2010) was selected to receive an additional $99 million in federal aid to help fund a second carbon sequestration project for which the company is awaiting regulatory approval. The goal is to store 1 million tons of CO2 per year for five years. The company hopes to begin the second project in early 2015.

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Using CO2 to Produce Geothermal Energy

SAN FRANCISCO - Researchers are developing a new kind of geothermal power plant that will lock away unwanted carbon dioxide (CO2) underground and use it as a tool to boost electric power generation by at least 10 times compared to conventional geothermal power.

The technology for this design already exists in different industries, and the researchers, led by Tom Buscheck, earth scientist from Lawrence Livermore National Laboratory, are hopeful that their new approach to the technology will expand the use of geothermal energy in the U.S. far beyond the small handful of states that can take advantage of it now. Heat Mining Company, LLC, a startup spun off from the University of Minnesota, expects to have an operational project based on an earlier form of this new approach in 2016.

At the American Geophysical Union meeting on Friday, Dec. 13, Buscheck and his colleagues fromThe Ohio State University, the University of Minnesota and Lawrence Livermore, will debut an expanded version of the design and explain the role that this new approach to geothermal energy production and grid-scale energy storage can have in addressing climate change.

The new power plant design resembles a cross between a geothermal plant and the Large Hadron Collider: it features a network of subsurface concentric rings of horizontal wells inside which CO2, nitrogen and water circulate to draw heat from deep below ground up to the surface, where it can be used to turn turbines and generate electricity.

"This well arrangement encircles the injected fluids with a subsurface hydraulic dam, functioning much like a hydroelectric dam. The intent is to recover the maximum energy benefit from fluid injection operations, a major improvement over conventional geothermal power systems," Buscheck noted.

The design contrasts with conventional geothermal plants in a number of important ways, explained study co-principal investigator Jeffrey Bielicki, assistant professor of energy policy in the Department of Civil, Environmental and Geodetic Engineering at The Ohio State University.

"Typical geothermal power plants tap into hot water that is deep underground,pull the heat off the hot water, use that heat to generate electricity and then return the cooler water back to the deep subsurface. Here the water is partly replaced with CO2 and/or another fluid," he said.

"Tt that there are benefits to using CO2, because it mines heat from the subsurface more efficiently than water," he continued."This combined approach (originally developed by Martin Saar at the University of Minnesota) can be at least twice as efficient as conventional geothermal approaches, and expand the reach of geothermal energy in the United States to include most states west of the Mississippi River."

The research team used computer simulations to design the system. In the simulations, a system of four concentric rings of horizontal wells about three miles below ground, with the outer ring being a little more than 10 miles in diameter, produced as much as a half a gigawatt of electrical power - an amount comparable to a medium-sized coal-fired power plant, and more than 10 times bigger than the 38 megawatts produced by the average geothermal plant in the U.S.

The simulations also revealed that a plant of this design might sequester as much as 15 million tons of CO2 per year, which is roughly equivalent to the amount produced by three medium-sized coal-fired power plants in that time.

"One of our key objectives when we began developing the CO2 plume geothermal technology was to find a way to help make CO2 storage cost effective while expanding the use of geothermal energy," said Jimmy Randolph, postdoctoral researcher in the Department of Earth Sciences at the University of Minnesota.

During the past year,  Buscheck added another gas - nitrogen - to the mix, resulting in a design that he and his colleagues believe will enable highly efficient energy storage at an unprecedented magnitude (at least hundreds of gigawatt hours) and unprecedented duration (days to months), provide operational flexibility, and lower the cost of renewable power generation.

"Nitrogen has several advantages," Buscheck explained. "It can be separated from air at lower cost than captured CO2, it's plentiful, it's not corrosive and will not react with the geologic formation in which it is being injected. And because nitrogen is readily available, it can be injected selectively. Thus, much of the energy required to drive the hot fluids out of the deep subsurface to surface power plants can be shifted in time to coincide with minimum power demand or when there is a surplus of renewable power on the electricity grid.

The distribution of stored nitrogen in the underground geothermal reservoir system is shown after 10 years of energy storage and production operations.

"Because we are storing energy in the form of pressurized fluids, we can further improve on this concept by selectively producing hot fluids when power demand is high, as well as reduce or stop that production when power demand is low. What makes this concept transformational is that we can deliver renewable energy to customers when it is needed, rather than when the wind happens to be blowing, or when spring thaw causes the greatest runoff."

The technology could possibly be used to expand the use of geothermal energy around the country. Right now, most geothermal power plants are in California and Nevada, where an especially strong geothermal gradient heats water underground. But the new design is so much more efficient at extracting heat that even smaller-scale "hotspots" throughout the western U.S. could generate power. (The eastern U.S. is mostly devoid of even small hotspots, so geothermal power would still be limited to a few particularly active areas such as West Virginia, Bielicki said.)

Another caveat: the geothermal plant would probably have to be connected to a large CO2 source, such as a coal-fired power plant, which was scrubbing the CO2 from its own emissions. That connection would likely be made by pipeline. Buscheck added, however, that a pilot plant based on this design could initially be powered solely by nitrogen injection, in order to prove the economic viability of using CO2. The study also showed that this design can work effectively with or without CO2, broadening where this approach could be deployed. The research team is currently working on more detailed computer model simulations and economic analyses for specific geologic settings in the U.S.

Co-authors on the presentation included Mingjie Chen, Yue Hao, Yunwei Sun, all of Lawrence Livermore. Work at the University of Minnesota and The Ohio State University is funded by the National Science Foundation, while work at Lawrence Livermore National Laboratory is funded by the U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy. 

Source: Lawrence Livermore National Laboratory