The Midwest consumes nearly 800 million megawatt-hours (MWh) of electricity per year to power homes, schools, businesses, and industry. This amounts to about 22 percent of total electricity consumed in the United States and requires the operation of more than 1,800 power plants and tens of thousands of miles of high-voltage transmission lines. How much electricity is used and how it is produced impacts the region's economy, landscape, environment, and public health.

Coal is the leading source of electric generation in the Midwest, currently accounting for almost 70 percent of electricity generated in the region in 2010. The other 30 percent was primarily natural gas and nuclear. Meanwhile, renewable sources accounted for only 3 percent. That mix is subject to change, however, as at least one quarter of the Midwest's total generation is from coal-fired units that are more than 40 years old* (U.S. EPA eGRID and U.S. EPA CAMD). The question of what will be built in its place remains to be answered. The relative cost of different resources as well as a number of new state and federal regulations, such as state Renewable Portfolio Standards, federal mercury standards, and EPA's proposed greenhouse gas performance standards for new sources will influence these decisions.

The region is home to a wealth of fossil fuel and renewable resources. These resources vary considerably by state. States will need to decide how best to deploy these resources to meet their electricity needs.

*Note, in order to calculate the most recent estimate of coal-fired generation by age, we used EPA's eGRID and Clean Air Markets Database (CAMD). These databases were mapped to each other using the DOE/EIA ORIS plant or facility code and the Unit ID to associate each unit's generation listed in CAMD to the unit's age listed in eGRID. The age for roughly 7 percent of the generation listed in the CAMD database could not be identified.

Electricity does not know state boundaries. As such, electricity imports and exports reflect the degree to which electricity is generated locally. The transmission lines span states and regions, and electricity generated in one state may be exported to another state. The interconnectedness of the grid makes it impossible to trace where the electricity from a specific power plant ends up.

Electricity generated in state provides local economic activity, but it may also have environmental impacts. As discussed in the emissions sections, states have implemented policies to reduce emissions. However, when crafting these policies, state policymakers are often concerned about how to balance protection of public health and the environment with the ability of the state's electricity generators to compete against generators out of state.

The Almanac provides net import and export figures, which compare the amount of electricity produced in state with in-state demand for electricity. States that are able to meet their demand with electricity produced in state, in theory, keep more revenue in their state and have more control over the fuel mix and emissions associated with electricity production. However, states can also be affected by out-of-state pollution that is generated from power plants located upwind from the state over which they have no control.

A number of state and federal laws, regulations, and policies that either are forthcoming or have been adopted in recent years aim at promoting renewable power generation and energy efficiency, and controlling air emissions from power generation. These laws and regulations have the potential to help change the mix of electricity generation in coming years.

Some of the major federal policies include the following:

• Renewable Electricity Production Tax Credit (PTC) and Business Energy Investment Tax Credit (ITC). These tax credits are available to taxpayers to help finance renewable energy projects. The PTC is currently set to expire at the end of 2012 for wind projects and at the end of 2013 for all other eligible sources. The ITC is set to expire at the end of 2016. Note that large-scale wind projects are not eligible for the ITC.
• Mercury and Air Toxics Standards (MATS). These rules set technology-based emissions standards for mercury and other toxic air pollutants for large power plants. These rules were finalized in December 2011.
• Cross-State Air Pollution Rule (CSAPR). CSAPR reduces SO₂ and NO_x emissions from large power plants through a multistate cap-and-trade program. These rules were finalized in July 2011, but a December 2011 court ruling directed the U.S. Environmental Protection Agency (EPA) not to implement the rule pending judicial review. As of February 2012, this review had not yet been completed. Click here for the latest status of this rule.
• Cooling Water Rule. These rules establish standards to reduce injury and death of fish and other aquatic life caused by cooling water intake structures at power plants and factories. EPA issued proposed rules in July 2011, but as of February 2012 the rules have not yet been finalized. Click here for the latest status of this rule.
• Performance Standards for Greenhouse Gases. These rules will establish greenhouse gas emissions standards for new, modified, and existing power plants. Click here for the latest information on these rules.

Some of the major state policies include the following:

• Renewable Portfolio Standards. Renewable Portfolio Standards require utilities to use renewable energy or renewable energy credits or certificates (RECs) to account for a certain portion of their retail electricity sales or generating capacity. Specific resources eligible for these programs varies by state.
• Net Metering. Some states allow net metering, where some utility customers--typically residential and smaller commercial customers--may sell the excess electricity generated from qualifying resources (e.g., solar or combined heat and power) back to the grid. This allows the owner of the renewable or other desirable technology to more fully capture its benefits.
• Energy Efficiency Resource Standards. Some states set energy efficiency targets for utilities or for the state as a whole. Utilities typically design these programs to include financial incentives to customers who install energy-efficient equipment or otherwise make their homes, businesses, and industries more efficient, thereby reducing overall demand from the utility.
• A number of states also have their own pollution control policies. Select different emissions sources on the map to begin exploring these policies.

You can learn more about the above policies and others by selecting the appropriate 'resource' and 'emissions' in the selection menu on the map.

Nearly one-half of the Midwest's total generation capacity has been built in the last 30 years. The majority of this new generation is natural-gas fired. Nearly one-third of the Midwest's total generating capacity is more than 40 years old, and one-fifth is more than 50 years old. Over 75 percent of the generation capacity more than 50 years of age is coal fired.

The older coal units are typically less efficient than more modern generators of the same size, meaning more coal needs to be consumed to produce the same amount of electricity. Over time these older generators will be replaced, and the question remains as to what will be installed. Between 2002 and 2010, roughly 52,000 MW of new generation capacity has been installed in the Midwest, which is 20 percent of total in-region capacity. The majority of the new generators are powered by natural gas (63 percent) and renewable sources (26 percent), with only 9 percent powered by coal. The remaining generation (2 percent) is powered by other fossil resources.

According to a 2010 study by the Brookings Institute, roughly 1.3 million jobs directly supported the production of fossil fuel-based energy, related products, and required machinery in the United States in 2010 (Brookings Institute). Meanwhile they estimated that the wind industry employed 24,000 people, and the solar technology industry employed almost 30,000 people. Absolute employment numbers, while important, only tell a part of the story, as total renewable generation is much lower than total fossil-based generation; wind and solar represented only 2.3 percent of electricity generation nationwide in 2010. Several independent studies that looked at trends in the clean energy industry found that the renewable energy sector generates slightly more jobs per megawatt of power installed, per unit of energy produced, and per dollar of investment than the fossil fuel-based energy sector (Brookings Institute, U.S. BLS, U.S. EIA, WRI).

Coal and natural gas emit different levels of pollutants when burned to produce electricity. Natural gas is effectively free of mercury and sulfur dioxide (SO₂) emissions, and in general, plants that are powered by gas emit less nitrogen oxides (NO_x) and carbon dioxide (CO₂) for each MWh of electricity produced than plants powered by coal. While the combustion of natural gas results in less CO₂ emissions than combustion of coal per Btu, the production and distribution of natural gas also can lead to leakage of methane, a potent greenhouse gas. This leakage reduces its global warming benefits. Precisely how much is under debate.

Under the Clean Air Act, new units are required to meet a 1.0 pound per MWh standard for NO_x emissions and a 1.4 pound per MWh standard for SO₂ emissions. As seen in the chart below, an average fossil-fired unit does not meet these standards without pollution control technologies. By installing at least one type of pollution control, these units emit 91-99 percent less NO_x and SO₂. Several states have also enacted emission standards for CO₂.

More information on where these emissions come from and how they can be reduced can be found in the Key Question section for the relevant emission.

Conventional electricity generation wastes two-thirds of the input fuel's energy potential during combustion, and even the most efficient combined-cycle natural gas power plants waste about one-half of the energy. Combined heat and power (CHP, or cogeneration) systems capture this otherwise wasted heat energy and use it to generate electricity and/or useful thermal energy. Due to its utilization of waste heat, CHP uses approximately 40 percent less energy than conventional production of heat and electricity (Brown, et al.,2011). For a given amount of electricity and heat utilization, CHP is more efficient, cheaper, and less emissions intensive than conventional combustion systems. Installation of CHP can raise total system efficiency to more than 80 percent (U.S. EPA).

Although combined heat and power (also known as CHP, or cogeneration) is a proven technology, it remains underutilized in the United States and in the Midwest. The Oak Ridge National Laboratory estimated that CHP amounted to 8.6 percent of U.S. electricity generation capacity and 12.6 percent of total U.S. electricity generation in 2008. A dozen industrialized countries have greater levels of CHP utilization, including Denmark, where more than 50 percent of the country's electricity is generated by CHP systems (ORNL, 2008).

As of 2011, the Midwest region has 11 GW of installed CHP capacity, out of 84 GW nationally. Whereas CHP amounted to 8 percent of national electricity generation capacity in 2009, the Midwest CHP share was slightly less than 5 percent.

Within the Midwest, 78 percent of CHP capacity is deployed in manufacturing facilities, with the balance of CHP installations located at commercial facilities, such as schools or hospitals. By comparison, at the national level, manufacturing facilities account for 62 percent of total installed CHP.

The figure below shows the breakdown of total installed combined heat and power (CHP) capacity and remaining technical potential among the 12 states of the Midwest. Technical potential is estimated on the basis of electric and thermal energy consumption data for various building types and industrial facilities. CHP potential was estimated per application based on facility employee and square footage data and remaining technical potential was calculated by subtracting existing CHP installations. For more information, see Hedman, 2010.

The status and rate of CHP utilization varies widely across the Midwest. Michigan and Indiana have the highest level of installed CHP capacity, while Illinois and Ohio have the largest remaining potential. Though some states stand out for having exceptional remaining CHP potential compared to currently installed capacity, every state in the Midwest has opportunities to reduce electricity and fuel costs through increased CHP deployment.

On a national level, a recent report from Georgia Tech found that increased CHP utilization could play a central role in reviving the American manufacturing sector.

While a few Midwestern states continue to pursue new policy and financing mechanisms to increase combined heat and power (CHP) utilization, barriers (described below) have contributed to the fact that regional uptake remains comparatively low (ORNL, 2008).

The American Council for an Energy Efficient Economy (ACEEE) recently published a state-level assessment of CHP utilization in the United States, including detailed discussions on specific barriers to CHP deployment. Recent studies by the National Academies of Sciences (2010) and the Oak Ridge National Lab (2008) provide useful overview discussions of barriers to CHP deployment. The 2008 Industrial Technologies Market Report issued by the National Renewable Energy Laboratory offers a concise summary of the present U.S. situation:

'Regulatory, policy, and institutional barriers persist, in spite of successes at the state and regional level, and recent federal legislation boosting tax credits for CHP. For example, electric rate structures linking utility revenues and returns to the number of kilowatt-hours sold act as a disincentive for utilities to encourage customer-owned onsite generation. In addition, CHP technology applications are impeded by interconnection issues, sundry technical barriers, and environmental permitting regulations that focus on heat input and do not recognize the higher overall efficiency improvements offered by CHP' (NREL, 2009).

Source: National Renewable Energy Lab (NREL), 2009 (2008 Industrial Technologies Market Report).

To increase the uptake of combined heat and power (CHP) technologies, policy options generally include financial incentives to positively promote investment and measures to remove market barriers to CHP deployment. Common options include the following:

• Energy Portfolio Standards (EPS) and Energy Efficiency Resource Standards (EERS) . An EPS is a regulatory policy that includes financial incentives. These standards are being used increasingly to support clean and renewable electricity in many U.S. states. EPS policies typically require that a certain percentage of electricity sold by a utility (e.g., MWh) is generated from renewable or other 'alternative' energy resources. Similar to an EPS policy, EERS policies require utilities to meet energy efficiency targets, reducing the amount of electricity or gas consumed by utility customers through the use of energy efficiency. An EPS or EERS policy can support CHP investments in cases where CHP qualifies as an eligible resource (Naik-Dhungel, 2009), thus making electricity or captured waste heat eligible for valuable credits, which utilities may use to comply with the law.
• Investment Tax Credit. One financial incentive to promote CHP utilization is the 10 percent federal Investment Tax Credit. Financial incentives reduce the payback period for capital intensive CHP installations, thus in this case, encouraging private sector investments.
• Output-based emissions standards. Selecting the appropriate new policies to reduce barriers to CHP may depend on the existing regulatory environment. For example, one approach to environmental regulation that supports CHP is output-based emissions standards (OBSs). Traditional 'input-based' regulations set emission limits based on the amount of fuel used (e.g., pounds of pollutant per million Btus), which can effectively discourage the use of certain energy efficiency technologies. Alternatively, output-based standards expressed as emissions per unit of useful energy output (e.g., pounds per MWh), which rewards generators that have the highest 'output' of product (e.g., MWh of electricity) and the lowest 'output' of pollutants, thus encouraging efficient fuel combustion technologies, including CHP. To be maximally effective, output-based regulations must include thermal and electric output of CHP processes.
• Grid access. Grid access can be a very important issue for facilities that seek to install a CHP unit on site (Chittum and Kaufman, 2011). Interconnection standards specify the technical requirements and procedural process by which utility customers connect electricity generation units to the grid. Historically, U.S. electric utilities have favored large-scale centralized power generation assets, with little incentive to facilitate a more distributed power generation model. For decades, the lack of standardized interconnection rules has inhibited investments in a range of distributed generation technologies (NREL, 2000).
  
  The interconnection issue has received increased attention in the past decade, with many state utility commissions adopting standards with common technical guidelines and even standard contracts (last decade, model interconnection standards were established through Federal Energy Regulatory Commission orders 2003 and 2006). Though implementation and enforcement will vary, the broader adoption of common interconnection standards should improve the investment environment for distributed generation technologies by reducing added costs, delays, and uncertainties. Most Midwestern states have adopted interconnection standards within the past few years that are technically comparable, though they often only apply to investor-owned utilities (Chittum and Kaufman, 2011).

To see what policies your state has adopted to promote CHP, visit ACEEE, or the Database of State Incentives for Renewables & Efficiency (DSIRE).

One hundred twenty four million short tons of coal were produced by six Midwest states in 2010 from a combination of surface and underground mines. This amounts to about 12 percent of total U.S. coal production. The primary producers are Illinois, Indiana, North Dakota, and Ohio (U.S. EIA, 2011). Kansas and Missouri accounted for only a small fraction of the region's production, and other states in the region had no coal production. Underground and surface mining methods are each used to obtain about half of the coal produced in the Midwest. Illinois and Ohio primarily use underground mining methods while North Dakota and Indiana primarily use surface mining (U.S. EIA, 2011).

In 2010 the Midwest consumed roughly 390 million short tons of coal. The vast majority of that coal is used to generate electricity (89 percent) and in industrial facilities (10 percent) (U.S. EIA). Coal contributed almost 70 percent to total electricity generation in the Midwest in 2010 (see charts at the bottom of the Almanac power generation map).

Over the past decade, the Midwest consumed more than three times more coal than it produced. The majority of the coal imports came from Wyoming (59 percent). West Virginia and Montana were also major sources of coal, with both states contributing 6.3 and 5.5 percent, respectively, to the Midwest's total coal receipts from outside the region (U.S. EIA).

In 2010, the Midwest produced 124 million short tons of coal. Three-quarters of that coal (74 percent) was consumed in Midwest states. Most of the exported coal was sent to southern states (30 million short tons). Among the Midwest coal destined for Midwest consumption, 84 percent is used to generate electricity. Other industrial facilities consume 15 percent of total Midwest coal, while commercial and coke plants consume very little of Midwest coal (EIA, 2011).

A 500 megawatt coal-fired plant running at 70 percent capacity will consume about 1.8 million short tons of coal each year in the Midwest. This equates to approximately 16,600 railcars of coal per year, or 45 railcars of coal each day.

*For purposes of these calculations, we assumed the plant is burning sub-bituminous coal and has a heat rate of 10,415 Btu per kWh (according to U.S. EIA this was the average heat rate for coal units in 2010). Also note that according to the Bureau of Transportation Statistics, a typical railcar holds 110 tons of coal.

Coal plants do not have a clear lifespan. It was once thought that power plants would retire after 30 to 40 years of operation. However, for a variety of reasons, coal plant lives have been extended. The current average capacity-weighted age of a U.S. coal-fired power plant is almost 40 years (U.S. EIA-860). According to the U.S. EIA, over 50 percent of the U.S. electric generation capacity was more than 30 years old, as of 2010, and around 12 percent was more than 50 years of age.

The Energy Information Agency (EIA) has projected future coal production for the United States out to 2035. Over the next 25 years, coal production in the United States is slated to increase roughly 25 percent (EIA, 2011).

While there are potentially recoverable resources within every coal seam, several factors influence whether a particular seam gets developed or not. The type and thickness of the rock above and between coal beds, the coal thickness, the depth of the coal, the existence of natural aquifers and preexisting fault lines impact the feasibility of developing a particular seam. What federal, state and private land can be developed may also be limited based on environmental concerns, including protection of wildlife habitat, water supply and quality issues, air quality issues, and preexisting infrastructure (existing roads, towns, and power lines).

Source: USGS, 2001

According to Energy Information Agency (EIA) data from 2010, the 12 Midwest states consumed 5 trillion cubic feet (Tcf) of natural gas, which accounted for 21.1 percent of natural gas consumed in the United States. The largest users of natural gas were Illinois, Michigan, and Ohio, representing 49 percent of the region's total consumption. Natural gas contributed about 5 percent to total electricity generation in the Midwest in 2010 (see charts at the bottom of the Almanac power generation map; this use accounted for about 9 percent of the region's total natural gas consumption.

In 2010, the region produced 648,663 MMcf of natural gas, less than one-seventh of the total natural gas consumed in the Midwest. The largest producers were Kansas, Michigan, North Dakota, and Ohio (U.S. EIA, 2011). However, new natural gas drilling technologies (such as horizontal drilling and hydraulic fracturing) are leading to significant increases in U.S. production and could lead to increases in regional production.

The Midwest region traditionally received a large portion of its natural gas supply from the Southwest region (including Texas and Oklahoma) and Canada through an interstate pipeline network (see figure below). The Rockies Express Pipeline, completed in the fall of 2009, enables the Midwest region to receive natural gas from Colorado as well (Kinder Morgan).

The majority of natural gas in the Midwest is consumed by residential and commercial users for heating and cooking, followed by industrial uses. Electricity generation represented 9 percent of the region's consumption. Natural gas vehicle fuel use represents the smallest consumptive use, with less than 1 percent of the total gas consumed in the 12 states (U.S. EIA Natural Gas Consumption, 2011)

In 2010, 648,663 Mcf of natural gas was produced in Midwest states, representing 2.9 percent of the U.S. total (U.S. EIA, 2011). No reporting system is available for natural gas that tracks flows from producer to consumer, unlike for coal where data based on net receipts is publicly reported and provides clear information about flows from one state to another. While information is available on net pipeline flows, these flows often have more to do with movement of gas through a state than from producers or to consumers within the state. As illustrated in the map of the national pipeline network in the response to the previous question, gas generally flows from the major producing areas (Texas, Louisiana, Oklahoma, the Rockies, and western Canada) to the major population centers in the Midwest, along the Eastern Seaboard, and the West Coast.

Most of the Midwest natural gas production comes from Kansas, Michigan, North Dakota, and Ohio. Michigan and Ohio are the highest net consumers of natural gas, with consumption exceeding production by factors of approximately five and ten, respectively. The two net producers, Kansas and North Dakota, are situated along pipelines that generally flow to the core of the Midwest.

Natural gas is trapped underground under varying geologic circumstances. 'Conventional' natural gas is typically trapped beneath impermeable rock in more porous formations, such as sandstone, that are relatively easy to access and produce. 'Unconventional' gas is found in formations that are more difficult to produce, many of which were once thought to be uneconomic. These 'unconventional' sources of gas include:

• Tight gas: natural gas trapped in tight pores within a rock that has low porosity and permeability
• Coalbed methane: natural gas trapped in coals
• Shale gas: natural gas trapped in shales

Hydraulic fracturing, or fracking has been used since 1949 (Montgomery, 2010) to stimulate production from an oil or gas well. This technique is used in both shale gas and tight gas formations. Fracking fluids are injected underground at pressures that fracture the shale, allowing the gas to flow. In the early 2000s, developers began applying hydraulic fracturing together with horizontal drilling (first used in 1929, (Carr, 2001)). The combination of these two technologies has led to significant increases in recent and forecasted production of natural gas in the United States. For more information on hydraulic fracturing, see http://fracfocus.org/.

Shale gas plays underlie eight of the Midwestern states. These plays are contained in the Bakken shale in North Dakota, the Gammon shale in North Dakota and South Dakota; the Niobrara shale in Nebraska; the Excello-Mulkey shale in Kansas; the New Albany shale in Indiana; the Devonian, Marcellus, and Utica shale in Ohio; and the Antrim shale in Michigan. At this time, the primary form of capturing gas from these formations is through horizontal drilling and hydraulic fracturing (U.S. EIA, 2011). As of January 2012, the Bakken, the Niobrara, the New Albany, the Devonian, the Utica, and the Antrim are all being explored for commercial potential or in varying stages of commercial development in Midwestern states. Within the Niobrara, the Devonian, and the Utica, test wells have been drilled by several companies to evaluate geographic features and determine potential production levels. The Atrium shale has been developed since the 1930s with vertical drilling and lower-pressure hydraulic fracturing to obtain natural gas from the formation. However, companies and geologists are now exploring the potential of horizontal drilling and high-pressure hydraulic fracturing to increase production. The Bakken in North Dakota is producing gas and associated hydrocarbons through horizontal drilling and hydraulic fracturing (GWPC, 2009).

In their Annual Energy Outlook 2011 (AEO, 2011), the U.S. Energy Information Administration (EIA) projects that natural gas consumption will rise roughly 20 percent above 2008 levels by 2016 in the Midwest. Nationwide gas consumption is expected to only rise by 8 percent over the same time period.

In recent years, natural gas production in the United States has been spurred by an increase in shale gas drilling. In 2009, 13 percent of natural gas produced in the United States came from shale formations, growing by an average of 48 percent each year between 2006 and 2010. U.S. shale gas production is expected to see a threefold increase by 2035 according to the AEO 2011 reference case. The Midwest currently holds about 4 percent of total shale gas reserves in the United States (U.S. EIA). There is considerable uncertainty surrounding the amount of shale gas that could be potentially recovered, which in turn affects the quantity of natural gas estimated to be available for consumption. As shown below, the potential range of natural gas consumption in the Midwest in 2035 differs by 700 billion cubic feet between the highest and lowest estimates by the EIA (U.S. EIA).

The U.S. Energy Information Administration (EIA) produces estimates of the recoverable natural gas resources that can be extracted from a given formation or region. The amount of this roughly projected recovery depends on a variety of factors, including but not limited to geological features of the source formation, current available technology, and the costs of extraction and final products. Estimates are likely to change when new information about these factors becomes available, such as additional detail about the specific geologic formations, often through increased exploration or development of different locations; new technological advancements to reach previously unattainable resources; or a change in technology that impacts the cost of extraction. It is not uncommon to see frequent readjustments for relatively new regions as more physical data becomes available.

The following are examples of recent causes for readjusted estimates:

• Increased technology. Large amounts of natural gas from shale sources have been introduced in the last decade due to advances in horizontal drilling and hydraulic fracking.
• Increased data. Michigan's remaining shale reserve estimates have decreased slightly in recent years in response to decreased production from wells in the Antrim formation.

The entire Midwest can generate electricity from photovoltaics (PV), and portions of Kansas, Nebraska, South Dakota, and North Dakota have sufficient solar resources for concentrating solar power (CSP). Electricity can be produced from PV panels at any solar intensity and through concentrated solar power (CSP) at resource levels greater than 5 kWh/m²/day. These geographic boundaries are shown in greater detail in the map titled Concentrating Solar Power Resource Potential.

The higher the solar resource level, the cheaper it is to produce electricity from PV or CSP. The Midwest does not have the highest solar resources in the United States. However, regions with comparable resources are moving ahead. According to NREL data, the Northeast has 17 percent (439 MW) of the total installed solar capacity in the United States (as of September 2011), while the Midwest has 2.0 percent (52.6MW) of total U.S. solar capacity.

Other countries throughout the world with either similar or lower solar resources (see figure below) have outpaced both the Midwest and the United States (2,660 MW). Germany, with solar resources similar to Alaska, has just over 17,000 MW of installed solar capacity. Spain, Italy, and Japan have between 3,500 and 4,300 MW installed.

Solar heating also has potential in the Midwest. Solar thermal technologies use sunlight to provide heat for domestic hot water, space heating, industrial process heat, and heating swimming pools (Minnesota Department of Commerce).

Source: NREL

Photovoltaic (PV) costs in the Midwest tend to be higher than alternative sources of electricity. In 2010 the average cost of PV was around $6 per watt (for state-specific average costs see this LBNL study). This price is higher than wind- or fossil-based generation. However, it is worth noting that costs have dropped by almost 40 percent over the past decade (LBNL), and some have projected these cost reductions to continue. The average cost for a concentrated solar power (CSP) plant is lower. With federal incentives, and without storage, CSP is more than $4 per watt in the United States. As with PV, design improvements are expected to reduce this cost in the future (NREL).

Concentrated solar arrays are typically large-scale projects that require about 10 square kilometers of flat land and access to water resources to cool the plant. These types of projects are typically not suitable for urban areas.

Photovoltaic (PV) panels can be installed in large arrays in fields or distributed in the built environment, such as on homes and businesses. The optimum location for PV installation is on a south-facing, shade-free roof. Panels can be installed on roofs that face southeast or southwest, but performance will be around 5 percent less. Eastern, western, and northern exposures are not recommended for solar PV systems. NREL's PVWatts and In My Backyard (IMBY) tool allows users to calculate the potential energy production and cost savings of grid-connected PV energy systems.

Two of the bigger policies that promote the development of solar-powered electricity generation are Renewable Portfolio Standards and net metering:

• Renewable Portfolio Standards (RPS). Renewable Portfolio Standards require utilities to use renewable energy or renewable energy credits (RECs) to account for a certain portion of their retail electricity sales or generating capacity according to a specific schedule. Sometimes these programs require that a percentage of the overall renewable requirement be met by specific technologies, such as solar. In the absence of such a solar 'carve out,' solar photovoltaics (PV) may not compete against wind power, which tends to cost less per unit of energy produced.
• Net metering. Solar energy, and thus electric production from PV, is strongest during the day when demand is at its highest. However, there may be a temporal mismatch between PV generation and electricity demand where the system is installed. For example, solar panels installed on a home will generate most of their electricity when a family is at work and the family's demand is low. Some states have net metering policies, which allow the excess electricity to be sold back to the grid when it isn't needed on-site. This allows the owner of the installed PV panels to fully capture their benefits.

DSIRE (Database of State Incentives for Renewables & Efficiency) has produced a comprehensive table listing all policies and incentives by state.

Based on analysis by the National Renewable Energy Laboratory (NREL), the Midwest could supply enough electricity to meet current demand in the region by covering less than 5 percent (55,000 km²) of available land with wind turbines. Such widespread installation may not be practical, and at this time there are other limits on how much electricity can be supplied by wind. Unlike fossil resources, wind is intermittent, and peak generation does not match peak demand. In addition, wind resources are also often far from electricity demand and require expansion of existing transmission infrastructure. NREL estimates that the Eastern Interconnection (covering most of the Midwest) could supply between 20 and 30 percent of projected electricity demand from wind resources by 2024 with upgrades and investment in transmission infrastructure. This is a substantial increase over the 3.4 percent provided in 2010. Wind could supply an even greater percentage of the region's electricity (and/or reduce the necessary transmission expansion) if there are significant advances in electric storage efficiency, or there is more widespread adoption of smart grid technologies that allow residents and businesses to adjust their consumption based on real-time electric production and pricing.

The Midwest produced 33,000 GW-hours of electricity from about 14,000 MW of installed wind capacity in 2010. This was just over one-third of the total wind-powered electricity generated in the United States. However, it amounts to just 3.4 percent of the fuel mix for electricity generation in the Midwest. Moving forward it is expected that regional wind generation will increase in response to state Renewable Portfolio Standards (RPS). According to a study by the Midwest ISO, RPSes in the Midwest will lead to the production of just under 100,000 GW-hours of wind energy by 2027, a threefold increase from current levels. Additional wind generation is projected to come online as a result of the Kansas RPS (20 percent of peak demand capacity from renewable sources by 2020), which was not included in the study.

One of the primary state-level policy drivers of wind development has been Renewable Portfolio Standards (RPS), which aim to increase the amount of renewable energy is delivered in a state. An RPS is most often imposed as requirement on utilities that must either procure renewable energy or buy renewable energy credits/certificates (RECs) to account for a certain portion of their retail electricity sales or generating capacity.

Two of the major drivers of renewable development at the federal level are the Production Tax Credit (PTC) and the Investment Tax Credit (ITC).

The PTC is a per-kilowatt-hour tax credit for electricity generated by qualified energy resources, which includes wind. Originally enacted in 1992, the PTC has been renewed and expanded numerous times. Wind projects in service by December 31, 2012 receive 2.2¢ per kWh (2011$; note the payment is indexed to inflation).The PTC for wind projects is set to expire after this deadline, while the PTC for all other eligible projects is set to expire at the end of 2013. Without this incentive, the United States could see a dramatic decline in annual wind capacity installation. This result was seen before in 2000, 2002, and 2004 when the federal PTC was allowed to expire (see figure below). At that time, annual installation of wind capacity decreased between 73 percent and 93 percent.

The ITC is available for the installation of a variety of renewable technologies, including small wind turbines. This includes projects 100 kW or less, which are often installed at individual homes, farms, and small businesses. The credit is equal to 30 percent of expenditures and is set to expire at the end of 2016. There is no maximum credit for wind turbines. Under the American Recovery and Reinvestment Act of 2009 wind energy systems of all sizes qualify for the ITC through the December 31, 2012 PTC deadline.

However, a number of other state and federal policies and financial incentives promote the development of wind-powered electricity generation. DSIRE (Database of State Incentives for Renewables & Efficiency) has produced a comprehensive table listing all policies and incentives by state.

Generally, areas designated with a wind resource of class 3 or greater are suitable for most utility-scale wind turbine applications, whereas class 2 areas are marginal for utility-scale applications but may be suitable for small wind turbine systems (100 kW capacity). Class 1 areas are generally not suitable, although a few locations (e.g., exposed hilltops) with adequate wind resource for wind turbine systems may exist in some class 1 areas. Wind class maps are only an estimate, however, and the suitability of any particular area requires an on-site wind assessment. Other factors that contribute to a site's feasibility for development of wind power include existing zoning codes, underlying geology, the location of local air traffic flight paths, and proximity to existing transmission lines.

According to the American Wind Energy Association (AWEA), the Midwest is home to at least 188 companies contributing to the wind energy industry. These facilities include major wind technology manufacturers, as well as smaller companies that supply the industry with components necessary for wind turbine development.

Three major wind industry manufacturers have invested in Illinois, including Trinity Structural Towers (a tower manufacturer) and Winergy (a gearbox manufacturer). At least 28 facilities in Illinois manufacture components for the wind energy industry as of mid-2011 (AWEA).

Brevini (gearbox manufacturer) is constructing its first U.S.-based facility and investing more than $60 million in Muncie, Indiana. At least 14 other facilities located in Indiana currently manufacture components for the wind energy industry, with 4 new facilities announced as of mid-2011 (AWEA).

Approximately $300 million has been invested at major wind energy industry manufacturing facilities in Iowa, including two turbine manufacturers, two major blade manufacturers, and a tower manufacturer. At least nine other manufacturers in Iowa are suppliers to the wind industry as of mid-2011 (AWEA).

After investing $50 million, Siemens' first American nacelle assembly facility opened in Hutchinson, Kansas in 2010. At least seven other facilities in Kansas manufacture components for the wind energy industry, with four new facilities announced as of mid-2011 (AWEA).

In 2008, Global Wind Systems announced its intention to build a new $30 million turbine manufacturing facility in Novi, Michigan. In 2010, URV USA announced plans to open the first wind-dedicated foundry in the United States. At least 31 other facilities in Michigan are suppliers to the wind energy industry, with 6 additional facilities announced as of mid-2011 (AWEA).

Two major wind energy industry manufacturing facilities are located in Minnesota, including SMI & Hydraulics (a tower manufacturer), and Wind Turbine Industrial (a small wind turbine manufacturer). A third, Moventas (a gearbox manufacturer), also announced plans to open a facility in the state. At least 16 other facilities manufacture components for the wind energy industry as of mid-2011 (AWEA).

At least seven facilities located in Missouri manufacture components for the wind energy industry, with two new facilities announced as of mid-2011 (AWEA).

Katina Summit, a major wind turbine tower manufacturer, opened a facility in Columbus, Nebraska in 2008 (AWEA).

Two major manufacturers for the wind energy industry are located in North Dakota, including LM Glasfiber (a blade manufacturer) and DMI Industries (a tower manufacturer) (AWEA).

At least 50 companies are located in Ohio that manufacture components for the wind energy industry as of mid-2011 (AWEA).

Molded Fiber Glass (blade manufacturing) has opened a $40 million manufacturing facility in Aberdeen, South Dakota (AWEA).

At least 22 facilities located in Wisconsin are suppliers to the wind energy industry, with 2 new facilities announced as of mid-2011 (AWEA).

It is expected that regional wind generation will increase threefold from current levels by 2027 in response to state Renewable Portfolio Standards (RPS), adding at least 81,000 GWh of wind generation to the transmission grid. This is equivalent to around 28,000 MW of new capacity. However, a 2010 study of the Midwest Independent Transmission System Operator (MISO) transmission network determined that the network is constrained and additional transmission infrastructure is needed to meet current and near-term renewable energy requirements, ensure reliable operation of the transmission grid, and relieve current and projected areas of congestion. New transmission infrastructure will also help facilitate the interconnection queue process, which enables MISO to determine the necessary upgrades required to connect each proposed generation project to the transmission system. As of January 2012, the MISO interconnection queue had more than 40,000 MW of wind power capacity waiting for transmission access. As a result of its 2010 study, MISO identified three potential transmission expansion scenarios that meet current renewable energy mandates and the regional reliability needs.

CO₂ is the predominant greenhouse gas (GHG) contributing to global climate change. Physicists have known for more than a century that greenhouse gases including CO₂, have heat-trapping properties that affect the temperature of the Earth's atmosphere. An increase in GHG concentration in the atmosphere leads to atmospheric and surface warming globally (NASA, 2011).

The United States accounts for nearly one-fifth of worldwide greenhouse gas emissions (based on the global warming potential of the emissions) (CAIT). In the United States, CO₂ accounts for 83 percent of U.S. GHG emissions by global warming potential (U.S. EPA, 2011). By 2005, the CO₂concentration in the atmosphere had increased by 39 percent compared with pre-industrial revolution levels (rising from 280 to 390 parts per million, from preindustrial to modern times), and the average annual growth rate of CO₂ concentrations has more than doubled since direct measurements began, in 1958 (NOAA, 2011).

This figure shows that rising concentrations of carbon dioxide in the atmosphere has grown steadily in concert with fossil fuel burning during the past two centuries (National Academy of Sciences).

The United States, like the rest of the world, is already experiencing the impacts of climate change. According to the National Academy of Sciences (NRC, 2011) and the Intergovernmental Panel on Climate Change, these include: more severe and more frequent heat waves, more intense precipitation events and severe droughts. Associated with these climatic shifts, we are seeing more severe flooding, crop failures, wildfires, and energy systems more prone to interruption (e.g., abundant water supplies are necessary for many forms of electricity generation). Sea level rise is already underway, which exacerbates the impacts of extreme weather events to coastal properties and infrastructure, as the intensity of storms is increasing (NRC, 2011). The U.S. Global Change Research Program provides more detail on region-specific climate change impacts on the Midwest and Great Plains.

Decades of air temperature measurements at locations around the globe tell the story of a warming world during the period from 1880 to 2011. This figure shows that scientists at NASA have estimated that air temperatures at the Earth's surface have risen by nearly 1 degree Celsius, since instrumental record keeping began more than a century ago.

This figure shows atmospheric concentrations of carbon dioxide over the last 10,000 years (large panel) and since 1750 (inset panel). Measurements are shown from ice cores (symbols with different colors for different studies) and atmospheric samples (red lines). The corresponding global warming effects, measured in terms of radiative forcings, are shown on the right axis of the large panel (IPCC). A positive forcing indicates warming while a negative forcing indicates cooling (MIT).

Carbon dioxide (CO₂) is emitted from the burning of fossil fuels (oil, gas, and coal) and waste, industrial processes, and deforestation (U.S. EPA, 2011). The largest source of manmade CO₂ emissions is fossil fuel combustion through power plants, automobiles, industrial facilities and other sources. The figure below displays U.S. emissions by source for 2009 (U.S. EPA, 2011). The CO₂ section of the Almanac contains similar information on CO₂emission sources for the Midwest.

CO₂ emissions from the power sector can be reduced through four main methods: employing demand-side energy efficiency and conservation practices; improving the efficiency of electric generation; using low-carbon or carbon-free energy resources; and the capture and storage of CO₂ from the combustion of fossil fuels or directly from the atmosphere.

As a general matter, using less electricity through increased efficiency and conservation reduces the amount of time that power plants need to run and thus the amount of fossil fuel that is combusted. This can be done by using more efficient appliances and equipment.

Opportunities also exist to improve the efficiency of power generation itself, allowing plants to produce the same amount of electricity while consuming fewer fossil fuels and thus emitting less CO₂.

Carbon dioxide emissions can also be reduced by employing lower-carbon and carbon-free energy resources in the production of electricity. For example, natural gas combustion emits roughly half of the CO₂ as coal combustion, and residual oil emits roughly 20 percent less CO₂ than coal (note that relative lifecycle emissions will differ). Biomass can be low carbon or even carbon-free on a lifecycle basis depending on the type used, the harvesting practices used, and the processes employed to covert feedstock to fuel. Switching from a higher-carbon fuel, such as coal or oil, to natural gas or biomass can reduce GHG emissions. Energy sources that generate carbon-free electricity include solar power, wind power, geothermal energy, hydropower, and nuclear power.

Finally, it is possible to capture the carbon dioxide generated from combustion at a power plant or other industrial facility and store it underground so that it cannot escape to the atmosphere. This process is commonly referred to as carbon dioxide capture and storage (CCS). See 'What is CCS?' below, for more information.

In 2007, the U.S. Supreme Court ruled that CO₂ is an 'air pollutant' under the Clean Air Act (CAA) and found that EPA has the authority to regulate CO₂ emissions. Following issuance of an endangerment finding in December 2009, EPA began to regulate CO₂ emissions starting with standards for vehicles. These regulations were finalized in May 2010. Since that time, EPA has begun to move ahead with regulations for the power sector, as summarized below.

• Preconstruction permits- New power plants and substantially modified existing power plants that are large emitters of carbon dioxide must obtain preconstruction permits that meet Best Available Control Technology (BACT) requirements. New source preconstruction permitting is governed by Title I, Parts C & D of the Clean Air Act , 42 U.S.C. Sections 7470-7490 and 7501-7505 and the regulations at 40 CFR Sections 51.165 and 51.166. EPA's 'Tailoring Rule' limits applicability to new facilities that emit at least 100,000 tons of GHGs per year and to modified sources that increase their GHG emissions by at least 75,000 tons per year.
• Performance standards- On December 23, 2010, EPA entered into a settlement agreement to issue rules to address greenhouse gas emissions from fossil fuel-fired power plants. The agreement called for EPA to propose performance standards for new and modified units under Section 111(b) of the Clean Air Act, and mandatory guidelines for existing units under Section 111(d) of the Clean Air Act. The agreement calls for EPA to finalize standards for the power sector by May 26, 2012.

  On March 27, 2012, EPA proposed performance standards for carbon dioxide emissions from new units. The proposed standards establish an output-based standard of 1,000 pounds of CO₂ per megawatt-hour generated. Click here for a summary of the proposal, and click here for additional information related to the new power plant standards.

  EPA has not yet proposed standards for carbon dioxide emissions from existing power plants. For an analysis of the level of reductions that could be achieved through GHG performance standards for new and existing power plants see, 'Reducing Greenhouse Gas Emissions in the United States Using Existing Federal Authorities and State Action.'

Carbon dioxide capture and storage (CCS) is a broad term that encompasses the process of capturing CO₂ from point sources (such as power plants and other industrial facilities); compressing it; transporting it mainly by pipeline to suitable locations; and injecting it into the deep subsurface geological formations for indefinite isolation from the atmosphere (WRI CCS Guidelines).

Although underground injection of CO₂ for enhanced oil recovery (EOR) and enhanced gas recovery (EGR) is a long-standing practice, CO₂ injection specifically for geologic storage involves potentially much larger volumes of CO₂ and larger scale projects than in the past. Long-term storage also presents unique technical issues, such as monitoring requirements and post-closure stewardship (U.S. EPA and WRI CCS Guidelines).

CO₂ is captured at oil and gas processing facilities and chemical production facilities as part of standard operating procedures. The captured CO₂ is typically generated from chemical processes at the plant and must be captured to complete the process. Capturing CO₂ from combustion is currently used at several power plants to coproduce food-grade CO₂ (National Energy Technology Laboratory).

CO₂ storage can take place in oil and gas reservoirs, saline formations, coal seams, basalts, and organic shale basins. However, storage sites must have the necessary characteristics to promote secure storage including a functional confining zone as well as the necessary injectivity and capacity (National Energy Technology Laboratory and WRI CCS Guidelines).

Although the components of CCS have been used by industry since the 1970s and there are examples of industrial large-scale integrated CCS projects in operation, the current cost, emerging status of the technology, and lack of climate policies that require reductions at the level where CCS would be necessary are barriers to its broader deployment. The cost of any one CCS project is highly dependent on the specific technologies chosen for capture and transport as well as the site-specific details of the local geology. In general, according to a 2011 report by the International Energy Agency titled 'Cost and Performance of Carbon Dioxide Capture from Power Generation,' the projected average cost of CO₂ avoided is USD 58/ton of CO₂ with a pulverized coal plant as the basis, $80 USD/ton of CO₂ with a natural gas combined cycle power plant, and $43 USD/ton of CO₂ with an coal-fired integrated gasification combined cycle power plant.

Not all geologic formations have the criteria needed for geologic storage, and determining whether or not a site is suitable for carbon dioxide capture and storage (CCS) requires collecting site-specific geological information. Suitable target formations must have sufficient porosity and permeability to allow injection of the captured CO₂ at the planned volumes as well as an overlying caprock that prevents the movement of CO₂ outside the storage reservoir. Other factors such as existing land use, population, and seismicity also affect decisions regarding potential projects. For example, a CCS project might move forward in an area that is seismically active, but only if the risks are thoroughly assessed prior to the project and paired with appropriate measurement, monitoring, and verification tools. For a full description of the criteria necessary for CCS, see Guidelines for Carbon Dioxide Capture, Transport and Storage.

EPA has finalized requirements for CO₂ injection and geologic storage under the authority of the Safe Drinking Water Act's Underground Injection Control Program. See 40 CFR Parts 124, 144, 145, 146, and 147 (Final Rule, January 2010): Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO₂) Geologic Sequestration (GS) Wells. The UIC program regulations are designed to protect underground sources of drinking water and establish a new well class (Class VI) for the specific purpose of carbon dioxide capture and storage (CCS). The regulations include requirements to ensure that wells used for geologic sequestration are appropriately sited, constructed, tested, monitored, funded, and closed.

EPA has also finalized reporting requirements for reporting greenhouse gas emissions from CO₂ storage under the authority of the Clean Air Act's Greenhouse Gas Reporting Program. See 40 CFR Part 98.440 (Final Rule, December 2010 with Proposed Technical Corrections August 2011): Mandatory Greenhouse Gas Reporting rule, Subparts RR-Geologic Sequestration of Carbon Dioxide and UU-Injection of Carbon Dioxide

The Mandatory Greenhouse Gas Reporting Rule includes provisions that outline how emissions from geologic storage and CO₂ injection will be reported.

EPA has proposed an exemption for CCS-related CO₂ streams under the existing hazardous waste rules. 'EPA concluded that the management of CO₂ streams under the proposed conditions does not present a substantial risk to human health or the environment, and will encourage the deployment of carbon capture and storage (CCS) technologies' (U.S. EPA).

A number of states in the Midwest have enacted laws that address many aspects of carbon dioxide capture and storage (CCS) (CCSReg, UCL Carbon Capture Legal Programme, and the Midwestern Governor's Association Regulatory Matrix).

Illinois has established state laws on the following aspects of CCS:

• Portfolio standard and mandate;
• Accounting and reporting; and
• Project-specific liability and property-rights

Clean Coal FutureGen for Illinois Act (enacted in 2007)*: For the FutureGen project, the state assumes long-term liability associated with CO₂ storage as well as any benefits or credits associated with storage. The bill also exempts the project from state tax.

SB 1592 Illinois Power Agency Act (enacted in 2007): Mandates electric utilities to charge a monthly fee creating a Renewable Energy Resources Trust Fund. A portion of this fund can be used for CCS. The bill authorizes the Illinois Power Agency to issue bonds for the construction of facilities that use Illinois coal with preference for projects that enable CCS and are in locations where the geology supports secure CO₂storage.

SB 1987 Clean Coal Portfolio Standard Law (enacted in 2009): Mandates that future electricity used in the state include 25 percent from coal plants that employ CCS. The bill further stipulates that these facilities should capture at least 50 percent of the CO₂, and 90 percent after 2017. Enhanced oil recovery (EOR) is included as a viable option for storage. The bill also requires accounting and reporting of CO₂ captured, stored, and emitted.

HB 3854 Carbon Capture and Sequestration Legislation Commission Act (enacted in 2009, repealed 2011): Establishes a carbon sequestration legislation commission tasked with reporting to the general assembly by December 2010 on CCS legislation needs. The report was not produced, and the act was repealed January 2011.

SB 1533 Illinois Power Agency Act Amendment (enacted in 2011): Amends the Illinois Power Agency Act (SB 1987) to allow for inclusion of clean coal brownfield synthetic natural gas (SNG) projects, provided they use 50 percent coal as a feedstock and captures and stores at least 85 percent of the emissions that would otherwise be emitted.

*This bill was written based on the original configuration of the U.S. Department of Energy (DOE) FutureGen project and refers to building a first-of-a-kind research facility.

Iowa does not have state-level laws pertaining to CCS.

Although the Michigan legislature considered several bills impacting CCS in 2009, none have been enacted.

Minnesota has established state laws on the following aspect of CCS:

• Study of geologic storage capacity

SF 2096 (enacted in 2007): Omnibus environment, natural resources, energy and commerce appropriations. Appropriated $90,000 for the study of geologic CO₂ storage capacity in Minnesota. The report was completed and is available online.

Although the Missouri legislature considered a bill on CCS liability in 2010, none have been enacted.

North Dakota has established state laws on the following aspects of CCS:

• CO₂ pipelines;
• Liability;
• Permitting;
• Accounting; and
• Tax incentives

NDCC 49-19-01 et. seq. (enacted in 2011): Common Pipeline Carrier: Establishes CO₂ pipelines as common carriers, establishes eminent domain for CO₂ pipelines, and regulates operation of CO₂ pipelines.

SB 2034 (enacted in 2009): An Act to amend and reenact subsection 5 of Section 57-51.1-03 of the North Dakota Century Code, relating to exemption from oil extraction tax on tertiary recovery projects that use carbon dioxide: Exempts enhanced oil recovery (EOR) projects that use CO₂ from the oil extraction tax, provided projects are certified as a qualified project.

SB 2095 (enacted in 2009): An Act to create and enact chapters 38-20 of the North Dakota Century Code, relating to the geologic storage of carbon dioxide; to repeal Section 38-08-24 of the North Dakota Century Code, relating to priorities in permitting carbon dioxide geologic storage projects; to provide a penalty; and to provide a continuing appropriation: This act calls for drafting of a state-level regulatory framework for CCS, including provisions for greenhouse gas accounting. It establishes eminent domain and unitization for CCS. The act also clarifies that the operator maintains liability for 10 years, establishes criteria for 'a certificate of completion,' and enables the transfer of long-term liability to the state. The act creates a CO₂ trust fund to fund long-term management and monitoring.

SB 2139 (enacted in 2009): An Act to create and enact a new chapter to Title 47 of the North Dakota Century Code, relating to ownership of subsurface pore space; to provide for application; and to declare an emergency: Establishes that the owner of the surface property is also the owner of the subsurface pore space needed for CCS.

SB 2221 (enacted in 2009): An Act to create and enact a new subsection to Section 57-60-01 and Section 57-60-02.1 of the North Dakota Century Code, relating to a credit against privilege taxes on coal conversion facilities for carbon dioxide capture; to amend and reenact Section 57-60-03 of the North Dakota Century Code, relating to measurement and recording of carbon dioxide capture; and to provide an effective date: Establishes methodology for determining the percentage of CO₂ captured from facilities, establishes a tax credit for CO₂ capture and associated reporting requirements.

Ohio does not have state-level laws pertaining to CCS.

South Dakota has established state laws on the following aspect of CCS:

• CO₂ pipelines

HB 1129 (enacted in 2009): An Act to ensure the integrity of pipelines to be used for the transportation of carbon dioxide for the purpose of enhanced oil recovery or geologic carbon sequestration: Establishes regulatory oversight for CO₂ pipelines by the Public Utilities Commission, defining CO₂ as consisting of more than 90 percent CO₂ and compressed to a supercritical state.

SB 60 (enacted in 2010): An Act to revise certain provisions regarding the siting of energy facilities by the Public Utilities Commission. Amends the language to include CO₂ pipelines under regulations for transmission facilities.

Wisconsin does not have state-level laws pertaining to CCS, although a September 2010 report outlines the potential for applying CCS to Wisconsin's coal fired power plants.

Landowners, industry, and governments are interested in who owns the injected CO₂ and receives any monetary benefit that comes with the ownership. In the United States, ownership of subsurface property differs from one state to the next. In general, surface owners also own the right to the geological pore space unless they have explicitly included carbon dioxide capture and storage (CCS) pore space in the lease or sale of any subsurface mineral rights or a state law declares CCS pore space a public good. Many states are taking legislative action to clarify pore space ownership rights for CCS (WRI, 2008). For example in the Midwest, North Dakota passed SB2139 in 2009, clarifying that the surface property owner does indeed also own the pore space needed for CCS.

The CO₂ itself (as well as any credits associated with it) is owned by the entity that injects it, unless ownership has been legally transferred to the subsurface property owner or to another entity.

Exposure to mercury can cause harm to the nervous system, brain, heart, kidneys, lungs, and immune system. Mercury is a naturally occurring element that exists in several forms throughout the environment, including coal. When coal is burned, mercury is released into the atmosphere and eventually gets deposited on land or into water. Aquatic microorganisms convert mercury found in water systems to methylmercury, its most common organic compound. This pollutant then bioaccumulates, or builds up, in fish and shellfish and the humans and other animals that consume them. Young children and unborn babies are most sensitive to high levels of methlymercury, as damage to their developing nervous systems can lead to severe disabilities.

Source: U.S. EPA

The largest source of man-made mercury emissions is coal-fired power plants (50 percent). Industrial boilers, combustion of hazardous waste, and steelmaking furnaces also emit large quantities of mercury. Mercury emissions and other hazardous air pollutants (HAP) can be largely prevented through the use of existing control technologies. These include the following:

• Precombustion controls, such as fuel switching, coal switching, and coal cleaning;
• Combustion modification methods used to control NO_x emissions;
• Flue gas cleaning technologies that can be used to control emissions of criteria pollutants and HAP; and
• Nontraditional controls, including demand-side management and energy conservation.

Source: U.S. EPA

EPA lists mercury as a Hazardous Air Pollutant (HAP) under Section 112 of the federal Clean Air Act, 42 U.S.C. Section 7412. In December 2011, EPA finalized a rule that establishes emissions standards for power plants. EPA estimates that the rule will prevent 90 percent of the mercury in coal burned in power plants from being emitted to the air.

All standards established pursuant to CAA Section 112(d)(2) must reflect Maximum Achievable Control Technology (MACT), the maximum degree of reduction in emissions of air. For existing sources, MACT cannot be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources (for which the Administrator has emissions information) for categories and subcategories with 30 or more sources or the best performing 5 sources for subcategories with less than 30 sources. This requirement determines the MACT floor for existing electric generating units. EPA may not consider costs or other impacts in determining the MACT floor. EPA must consider cost, non-air quality health and environmental impacts, and energy requirements in connection with any standards that are more stringent than the MACT floor (beyond-the-floor controls) (Source: U.S. EPA).

EPA's recently finalized mercury standards will establish minimum levels of control in all states. A number of states in the Midwest previously enacted regulations to reduce mercury emissions, including Illinois, Michigan, Minnesota, and Wisconsin. The state standards will remain in effect, but will only control in cases where they are more stringent than the federal standards. Information on those standards can be found here.

In 1999, EPA estimated that existing pollution controls that limit emissions of particulate matter, SO₂, and NO_x at power plants prevented about 33 percent of the mercury burned in coal from being emitted into the atmosphere. Since 1999, mercury emissions have decreased by 41 percent in the United States and 37 percent in the Midwest due to the increased installation of these pollution controls. Additional reductions of mercury emissions are expected to result from EPA's Mercury and Air Toxics Standards (MATS), which was signed in December 2011. The rule will immediately affect new fossil-fuel generators, and will begin to affect existing fossil-fuel generators in December 2014. When fully implemented, the rule will prevent 90 percent of the mercury burned in coal from being emitted into the atmosphere.

The primary public health and environmental impacts from nitrogen oxides (NO_x) are caused by their reaction in the atmosphere to form ground-level ozone, fine particulate matter, and acid rain. Exposure to nitrogen dioxide (NO₂, one of the nitrogen oxides) can irritate the human respiratory system and exacerbate asthmatic symptoms.

NO_x forms ground-level ozone by reacting with volatile organic compounds (VOCs) in the presence of sunlight. Exposure to ground-level ozone can lead to a variety of health impacts, such as inflammation of the lining of the lungs and reduced lung functioning. Permanent scaring of lung tissue may occur from repeated exposure.

Atmospheric NO_x can react with other compounds in the atmosphere to form fine particles that can cause a variety of health effects, including reduced lung function, aggravated asthma, difficulty breathing, irregular heartbeat, nonfatal heart attacks, and death in people with heart or lung disease (U.S. EPA). Fine particles also lead to regional haze.

NO_x also contributes to the formation of acid rain. Once in the atmosphere, NO_x can travel downwind from where it was emitted and fall to the ground as acid rain. Once on the ground, acid rain mixes with soil and other water sources, affecting plants and animals that come in contact with it.

EPA has set National Ambient Air Quality Standards (NAAQS) for nitrogen dioxide, ground-level ozone, and fine particulate matter. As required by the Clean Air Act, the NAAQS are set at levels EPA believes to be protective of human health and the environment with an adequate margin of safety. At this time no area in the United States is considered to be in nonattainment with the NAAQS for NO₂. Click here to see whether your area has been designated as non-attainment for ozone, and here to see whether your area has been designated as nonattainment for particulate matter.

Source: U.S. EPA.

According to the EPA, the power sector is the third-largest contributor of nitrogen oxides emissions, after on-road vehicles and nonroad equipment (such as construction equipment, marine vessels, and lawn and garden equipment). Industrial boilers and manufacturing processes also emit NO_x.

NO_x can form during combustion through the oxidation of nitrogen chemically bound to the fuel, and through the reaction of atmospheric nitrogen (N₂) with excess oxygen (O₂). For coal-fired power plants, oxidation of chemically bound nitrogen typically accounts for the majority of NO_x that is formed. In contrast, fuel nitrogen is not a significant contributor to NO_x emissions in natural gas-fired power plants (NETL).

There are several strategies for reducing nitrogen oxides emissions from power plants, including the following:

• Precombustion controls, such as fuel switching;
• Modified combustion, using technologies such as low-NO_x burners;
• End-of-stack control technologies, such as selective catalytic reduction; and
• Demand-side management and other energy conservation measures.

Source: U.S. EPA.

EPA has implemented numerous regulatory programs for the control of nitrogen oxides emissions.

State Implementation Plans (SIP)

• States are required to have state implementation plans that include measures to preserve air quality in counties that are in attainment of the National Ambient Air Quality Standards (NAAQS) and improve air quality in counties in nonattainment.
• Where nitrogen oxides emissions from power plants are concerned, state implementation plans most often consist of regulations to implement federal permitting requirements and apply federal new source performance standards.
• State SIPs are required by Section 110 of the federal Clean Air Act, 42 U.S.C. Section 7410.

Preconstruction Permits

• New power plants and substantially modified existing power plants that are large emitters of nitrogen oxides must obtain preconstruction permits that meet either Best Available Control Technology (BACT) requirements in attainment areas or Lowest Achievable Emissions Rate (LAER) in nonattainment areas.
• Preconstruction permitting for nitrogen oxides from power plants involves the imposition of an emissions limit tied to the Best Available Control Technology for a new plant in an area in attainment for ozone and NO₂ and tied to the Lowest Achievable Emissions Rate (LAER) for a new plant in a nonattainment area for ozone.
• New source preconstruction permitting is governed by Title I, Parts C & D of the Clean Air Act, 42 U.S.C. Sections 7470-7490 and 7501-7505 and the regulations at 40 CFR Sections 51.165 & 51.166.

New Source Performance Standards

• Certain new power plants and substantially modified existing power plants must meet applicable new source performance standards prescribing emissions rates.
• New Source Performance Standards control emissions through the imposition of a maximum emissions rate for new boilers and turbines. These emissions rates are included in the operating permits of the power plants.
• New Source Performance Standards for power plants are promulgated under Section 111 of the Clean Air Act, 42 U.S.C. Section 7411 and are found at 40 CFR Part 60, Subparts Da and KKKK.

Cross-State Air Pollution Rule

• The Cross-State Air Pollution Rule also aims to reduce nitrogen oxides emissions through a multistate cap-and-trade program aimed at reducing cross-state ozone transport.
• The Cross-State Air Pollution Rule covers all fossil-fuel generating units with a nameplate capacity of 25 MW or greater. The program imposes an aggregate emissions cap covering the affected plants. EPA then issues emissions allowances equal to the cap. Every power plant subject to the program must monitor its emissions and report the emissions to EPA. At the end of each year, every plant must hold enough emissions allowances to cover all of its nitrogen oxides emissions.
• The Cross-State Air Pollution rules were created under Section 110(a)(2)(D) and were published in the federal register on August 8, 2011. A December 2011 court ruling directed EPA not to implement the rule pending judicial review. As of February 2012, this review had not yet been completed. Click here for the latest status of this rule.

In general, state regulation of nitrogen oxides from power plants takes place under the federal Clean Air Act through state implementation plans and through the state administration of federal permitting requirements.

Since 2005, NO_x emissions have decreased by 37 percent in the United States. Along with other final state and EPA actions, the Cross-State Air Pollution Rule (CSAPR) will further reduce power plant NO_x emissions by 54 percent compared to 2005 levels by 2014 in the covered region (including most of the eastern United States). Midwestern states covered by CSAPR (all but North and South Dakota) are expected to see slightly higher reductions by 2014 (U.S. EPA).

Sulfur dioxide (SO₂) is a reactive air pollutant that can cause adverse respiratory impacts, especially for vulnerable groups such as children, the elderly, and asthmatics. Atmospheric SO₂ reacts with other compounds in the atmosphere to form fine particles that can cause a variety of health effects, including reduced lung function, aggravated asthma, difficulty breathing, irregular heartbeat, nonfatal heart attacks, and death in people with heart or lung disease (U.S. EPA). Fine particles also lead to regional haze.

SO₂ also contributes to the formation of acid rain, or acid deposition. Once in the atmosphere, SO₂ can travel downwind from where it was emitted and fall to the ground as acid rain. Once on the ground, acid rain mixes with soil and other water sources, affecting plants and animals that come in contact with it.

EPA has set National Ambient Air Quality Standards (NAAQS) for SO₂and particulate matter. As required by the Clean Air Act, EPA has established National Ambient Air Quality Standards for SO₂and particulate matter at levels believed to be protect human health and the environment with an adequate margin of safety. The entire Midwestern region is in attainment with the SO₂ NAAQS. Click here to see whether your area has been designated as non-attainment for particulate matter.

Source: U.S. EPA.

Close to three-quarters of all sulfur dioxide emissions derive from fossil fuel combustion by power plants, and another one-fifth is attributable to industry (U.S. EPA). Coal has the greatest sulfur content, though the sulfur content various significantly based on the source of the coal. Certain fuel oils also contain high sulfur levels. There is little sulfur in natural gas.

Several possible strategies for lowering sulfur dioxide emissions from power plants exist, including the following:

• Pre-combustion controls, such as fuel switching, coal switching, and coal cleaning;
• End-of-stack control technologies, such as scrubbers; and
• Demand side management and other energy conservation measures and measures to conserve energy.

Source: U.S. EPA.

State Implementation Plans

• States are required to have state implementation plans that include measures to preserve air quality in counties that are in attainment of the National Ambient Air Quality Standards (NAAQS) and improve air quality in counties in nonattainment.
• Where sulfur dioxide emissions from power plants are concerned, State Implementation Plans (SIP) often consist of regulations to implement federal permitting requirements and apply federal new source performance standards.
• SIPs are required by Section 110 of the federal Clean Air Act, 42 U.S.C. Section 7410.

Preconstruction Permits

• New power plants and substantially modified existing power plants that are large emitters of sulfur dioxide must obtain preconstruction permits that meet either Best Available Control Technology (BACT) requirements in attainment areas or Lowest Achievable Emissions Rate (LAER) in nonattainment areas.
• For the entire Midwestern region, preconstruction permitting for sulfur dioxide emissions from power plants involves the imposition of an emissions limit tied to the BACT for the new plant.
• New source preconstruction permitting is governed by Title I, Parts C & D of the Clean Air Act, 42 U.S.C. Sections 7470-7490 and 7501-7505 and the regulations at 40 CFR Sections 51.165 and 51.166.

New Source Performance Standards

• Certain new power plants and substantially modified existing power plants must meet applicable new source performance standards prescribing emissions rates.
• New Source Performance Standards control emissions through the imposition of a maximum emissions rate for new boilers and turbines. These emissions rates are included in the operating permits of the power plants.
• New Source Performance Standards for power plants are promulgated under Section 111 of the Clean Air Act, 42 U.S.C. Section 7411 and are found at 40 CFR Part 60, Subparts Da and KKKK.

Acid Rain Program

• The Acid Rain Program is a federal cap-and-trade program that covers all fossil-fuel generating units with a nameplate capacity of 25 MW or greater. The program imposes an aggregate emissions cap covering the affected plants. EPA then issues emissions allowances equal to the cap. Every power plant subject to the program must monitor its emissions and report the emissions to EPA. At the end of each year, every plant must hold enough emissions allowances to cover all of its sulfur dioxide emissions.
• The Acid Rain Program was created under Title IV of the Clean Air Act and regulations are found at 40 CFR Parts 72 and 75.

Cross-State-Air Pollution Rule (CSAPR)

• The Cross-State Air Pollution Rule aims to reduce sulfur dioxide emissions through a multi-state cap-and-trade program that exists alongside the Acid Rain program, but the CSAPR achieves deeper reductions.
• The Cross-State Air Pollution rules were created under Section 110(a)(2)(D) and were published in the federal register on August 8, 2011. A December 2011 court ruling directed EPA not to implement the rule pending judicial review. As of February 2012, this review had not yet been completed. Click here for the latest status of this rule.

Since 2005, SO₂ emissions have decreased by 48 percent in the United States. Along with other final state and EPA actions, the Cross-State Air Pollution Rule (CSAPR) will further reduce power plant SO₂ emissions by 73 percent compared to 2005 levels by 2014 in the covered region, which includes most of the eastern United States. Midwestern states covered by CSAPR (all but North and South Dakota) are expected to see similar reductions by 2014 (U.S. EPA).