The problem is that energy efficiency is not free. Appliances with greater energy efficiency cost more money—sometimes a lot more and frequently take more time to do the same amount of work.

Americans, not policymakers, should be free to choose which appliances make the most sense for their families instead of being forced to purchase more expensive and more energy efficient appliances.

Energy efficiency mandates are based on the premise that Americans consumers do not make wise choices about energy efficiency without the government forcing them to make “good” choices. It is a dubious claim. Consumers pay attention to their electric bill, and that is especially the case with commercial users of appliances.

Mandating greater energy efficient makes the appliances and equipment more expensive. In 2006, the Consumer Reports Best Buy for top-load washing machines only cost $380.[1] That was before the federal energy efficiency mandate for washing machines. In 2007, when washing machines had to comply with the new energy efficiency mandate, Consumer Reports said that “we can’t call any washer a Best Buy because models that did a very good job getting laundry clean cost $1,000 or more.”[2]

Since then, washing machines have improved—but the energy efficiency mandates still make them more expensive than they would otherwise be. The least expensive washing machine Consumer Reports recommends still costs $480[3] and the next lowest-priced recommend washing machine costs $650.[4] If a consumer saves $15 a year[5] in energy costs by using one of these more efficient washers, it takes nearly 5 years to recoup the extra costs of the $480 model and over 16 years to recoup the extra cost of the $650 model (even adjusting for inflation from 2006 to 2010).

Federal officials who desire to mandate energy efficiency standards apparently assume that households and businesses are not making smart choices about energy efficient appliances. This is not borne out by actual data. According to data from the Association of Home Appliance Manufactures, household appliances are becoming much more efficient. Between 1980 and 2008, air conditioners became 41.5 percent more energy efficient, dishwashers became almost twice as energy efficient, and refrigerators became nearly three times as energy efficient.[6] The graph below shows the percent improvement in energy efficiency of standard household appliances:

Americans are intimately aware of the costs of their utility bills and are always looking for ways to balance the convenience of their appliances with energy savings. When federal regulators step in and mandate energy efficiency improvements, the mandate increases the price of appliances and limits Americans’ choices. Actual data shows that appliances are becoming more energy efficient over time. There is no need for lawmakers to step in and artificially limit our choices.

[2] Consumer Reports Annual Buying Guide, Jan. 1, 2008, available at http://www.accessmylibrary.com/coms2/summary_0286-34226514_ITM.

[3] Consumer Reports, Washers & Dryers, Feb. 2010 p. 47. The model is a GE WJRE5500G.

[4] Id. at 46. The model is a Frigidaire Gallery GLTF2940F.

[5] In 2009, Consumer Reports noted online in subscriber only section of their website that “Each improvement in energy-efficiency scores, from good to very good, for instance, cuts an average of $10 to $20 from your annual energy expenditures.” The 2010 washing machines are rated at “Very Good” for energy efficiency, while the 2006 washer was rated as “Good” on energy efficiency.

[6] Data from the Association of Home Appliance Manufactures, cited by Mark J. Perry at http://mjperry.blogspot.com/2009/10/chart-above-shows-significant-increases.html.

Affordable energy would help to heal an ailing economy because affordable energy facilitates economic growth. Energy’s share of Gross Domestic Product is one measure of the relative importance of energy in the overall economy. While the share of energy in the U.S. economy has declined from its high in the early 1980’s, it still remains a large component, and energy as a share of world GDP is also large.

United States

The Energy Information Administration calculates the share of U.S. Gross Domestic Product (GDP) that is energy-related and publishes it in its Annual Energy Review.[i] Prior to the embargo of 1973-74, total energy expenditures constituted 8 percent of U.S. gross domestic product (GDP), the share of petroleum expenditures was just under 5 percent and natural gas expenditures accounted for 1 percent. The price shocks of the 1970s and early 1980s resulted in these shares rising dramatically to almost 14 percent, 8 percent, and 2 percent respectively, by 1981. Since that time, the shares have fallen until the early part of this decade when they began to rise again.

The energy component still remains a major share of GDP in 2006 at 8.8 percent.[ii] In 2006, Americans spent $1,158 billion on energy, 2.7 times more than in 1981, when they spent $427 billion on energy (both in nominal dollars).  The U.S. economy in 1981, however, was about one-fourth of its 2006 size. That fact and lower Middle Eastern crude oil production due to Iraq’s invasion of Iran raising energy prices in 1981 are some of the reasons why energy represented a larger share of GDP in that year.

Another reason for energy’s lower share of GDP since 1981 is that energy intensity has been declining. Energy intensity is energy consumption (measured in physical terms, such as BTUs) per dollar of GDP. Its decline means that the American economy uses less physical energy to produce a dollar of output (GDP) because of efficiency improvements in energy consuming technologies and structural shifts in the U.S. economy. The U.S. economy has become more service oriented, requiring less energy than many manufacturing industries, such as steel and cement, that have been moving offshore due to competition and lower energy prices in other parts of the world.

World

Neither the Energy Information Administration nor the International Energy Agency publishes energy expenditures for the world. Thus, there is no definitive number or source of energy expenditures as a percent of the global economy. Energy journalist Robert Bryce estimated global energy expenditures at $5 trillion, of which at least $4.4 trillion is directly derived from hydrocarbons—coal, natural gas, and petroleum.[iii] According to Bryce, total global energy use in 2008 was 11.29 billion tons of oil equivalent, which is about 82.8 billion barrels, using the conversion factor of 7.33 barrels per ton. Assuming an average oil price of $60 per barrel, results in energy expenditures at $4.968 trillion.[iv] The world economy in 2008 was $60.587 trillion. Thus, the energy share of the global economy is about 8.2 percent according to this method.

Another way to calculate the global share that energy represents of world GDP is to assume that the entire world shares U.S. prices for energy and a fuel distribution similar to that of the U.S. This improves upon the calculation by recognizing other fuel prices besides that of oil, but may still overstate the global share that energy constitutes of GDP since the U.S. uses more oil (about 3.5 percentage points more) and less coal  (about 4.5 percentage points less) than the world. Using the following formula,

(US physical energy use / US GDP) /percent of US economy that is energy = (world physical energy use / world GDP) / percent of world economy that is energy, and solving for the percent of the world economy that is energy results in a 7.9 percent share.  Global energy intensity (world physical energy use/world GDP) can be obtained from the International Energy Agency’s Key World Energy Statistics 2009.[v]

Conclusion

Under either method of estimation, about 8 percent of GDP is associated with energy expenditures worldwide, and a slightly higher 9 percent is associated with U.S. GDP. In many countries, this may be second only to health care costs, which are almost 16 percent of GDP for the U.S., but in the 8 to 11 percent range for many European countries and Canada.[vi] This means that energy prices, like health care, have a large effect on the economy and policies that promote energy price increases may result in negative consequences to economic growth. Politicians worldwide should be cautious regarding energy policies that may disrupt their economies.

[ii] The share was also 8.8 percent in 2007 when energy expenditures were $1,233 billion, and GDP was $14,078 billion. See www.bea.gov/national/pdf/dpga.pdf and www.eia.doe/emeu/states/sep_prices/notes/pr_print2007.pdf .

[iii] Robert Bryce, Energy Tribune, December 18, 2009, www.energytribune.com/articles.cfm?aid=2746

[iv] Roger Pielke Jr.’s Blog: How Large is the Global Economy? December 21, 2009, http://rogerpielkejr.blogspot.com/2009/12/how-large-is-the-global-energy-economy.html
[v] International Energy Agency, Key World Energy Statistics 2009, http://www.iea.org/publications/free_new_Desc.asp?PUBS_ID=1199

[vi] Health Care Spending as Percentage of GDP, Robert Wood Johnson Foundation, June 30, 2009, http://www.rwjf.org/pr/product.jsp?id=45110 , and The Commonwealth Fund, January 29, 2007,

www.commonwealthfund.org/Content/Publications/Fund-Reports/2007/Jan/Slowing-the-Growth-of-U-S-Health-Care-Expenditures–What-Are-the-Options.aspx

One criticism was that we focused too heavily on EIA’s estimate that fossil energy will continue to be the dominant source of U.S. energy and economic growth for decades, accounting for nearly 80 percent of our energy needs in 2035, and neglected to mention that EIA also projects a significant increase in renewables.

In his tweet, one green journalist points out that the EIA report indicates renewables will increase by 20 percent. Actually, that’s an understatement. EIA predicts wind, solar, and some biomass (read: politically correct “renewable” sources) will increase by 88 percent[1]. That sounds impressive, but even with their dramatic increase EIA estimates that by 2035 these politically correct renewables will only produce about 8 percent of our total energy consumption. And that is despite billions of dollars in subsidies, set-asides, and preferential treatment.

In comparison, EIA estimates that our most efficient, proven, and prolific (albeit not as politically fashionable) sources of carbon-free and renewable energy – nuclear and hydroelectric power – together will provide for 10.8 percent of our energy needs in 2035 (2.6 percent from hydro and 8.2 percent from nuclear).

But how accurate are these forecasts? The EIA is taking a glimpse nearly 30 years into the future, after all.

The oldest Annual Energy Outlook on EIA’s website is from 1996. Their forecast for renewables’ slice of the energy pie in 2008 was 7.39%; the actual number last year was 7.36%. That’s very accurate, and of all the energy sources, their forecasts were the closest on renewable energy.

The question of whether their forecast will be that precise thirty years from now remains to be seen.  However, we’re confident it will be more accurate than many other projections we’ve seen over the years.

Although the EIA projects a large percentage increase in renewable energy by 2035, this will account for less than 10 percent of our total energy use. The American taxpayers have contributed billions of dollars to renewables for decades and yet EIA predicts they will continue to play a minor role in our energy supply thirty years from now.

• In 2008, solar represented 0.09 percent of all energy consumed in the U.S. [1] and 0.02 percent of all electricity generated in the U.S.[2]

• In 2008, solar generating capacity in the U.S. totaled 514 megawatts and generated 843 million kilowatt hours.[3] Solar turbines generated only a percentage of their theoretical maximum output due to their intermittency (the sun does not always shine).
• In 2006, photovoltaic cell and module shipments totaled 337 megawatts, and were estimated at 430 megawatts in 2007. These include communications, transportation, health, and grid-interactive and remote electric generation applications. [4]
• Due to incentives in the stimulus and to state mandates highlighted below, the Energy Information Administration projects solar thermal and photovoltaic generating capacity in the electric power sector to increase to 0.60 gigawatts by 2010, 1.02 gigawatts by 2020, and 1.24 gigawatts by 2030. End-use photovoltaic capacity is expected to grow to 1.86 gigawatts in 2010, 10.78 gigawatts in 2020, and 12.3 gigawatts in 2030. Together, generation from solar is projected to increase to 4.12 billion kilowatt hours by 2010, 20.11 billion kilowatt hours by 2020, and 23.22 billion kilowatt hours by 2030. This level of projected solar generation in 2030 represents 0.46 percent of total U.S. electricity generation.[5]
• Because solar power is available only when the sun shines and varies with the seasons of the year, statements about how solar units can produce enough electricity to serve a large number of homes are misleading. Since a solar unit cannot supply power continuously, dispatchable generators (usually fossil-fuel) are required to provide back-up power to the system.

Transmission Facts

• Total spending on new transmission by all investor-owned utilities in 2006 [current dollars] was $6.9 billion.[6] This figure underestimates total transmission spending since it excludes Government-owned utilities and cooperatives.
• According to a November 2008 study by Brattle Group, total investment in transmission and distribution through 2030 is expected to total $880 billion, where $298 billion would be for transmission and $582 billion would be for distribution. The figure includes integration of 214 gigawatts of new generating capacity of which 39 gigawatts is for renewable technologies required under existing state renewable portfolio standards, continued installation of a “smart grid”, accommodation for new end-use technologies such as plug-in hybrid electric vehicles, and bringing new efficiencies and service options to end use customers. The authors caution that the figure could be an underestimate since it is derived from shareholder-owned electric utility expenditure data that excludes investments made by electric cooperatives and Government-owned utilities. [7]
• There is no standard definition of a “smart grid”. It generally refers to technologies that: 1) provide customers with information and tools that allow them to be responsive to system conditions, 2) ensure more efficient use of the electric grid, and 3) enhance system reliability. The latest federal stimulus law provides $11 billion for smart grid technology, including $4.5 billion for smart-technology matching grants. [8] The $11 billion is a small percentage of what’s needed to get to the $880 billion mark, and that amount does not support a 20 percent renewable scenario by 2030.
• In Europe, it is estimated that 1.2 trillion Euros ($1.55 trillion) would be needed to build a super grid that captures offshore wind, hydropower, and solar panel arrays. [9] It would require a new network of cables and interconnectors to bring offshore generated electricity to land and modernization of the onshore grid to deal with sudden changes in supply and demand and clear bottlenecks.

Solar Subsidies

• The Energy Information Administration estimates that total Federal subsidies for electric production for fiscal year 2007 from solar power are $24.34 per megawatt hour, compared to 44 cents for traditional coal, 25 cents for natural gas and petroleum liquids, 67 cents for hydroelectric power, and $1.59 for nuclear. Solar subsidies for non-electric production in fiscal 2007 totaled $2.82 per million Btu, second only to ethanol/biofuels at $5.72 per million Btu. (Figures are in 2007 dollars.) [10]

• According to the General Accounting Office, in fiscal year 2007, solar received 9.2 percent of all federal research subsidies to power generation but produced only 0.016 percent of U.S. electricity. Per kilowatt-hour, this was 1255 times higher than the amount allocated to coal, most of which was spent to develop cleaner technologies. Coal produced 51.4 percent of all U.S. electricity in fiscal year 2007.[11]

Policies Affecting Solar

• While no federal renewable portfolio standard (RPS) exists, 28 states and the District of Columbia have a renewable portfolio standard mandating a certain percentage of a utility’s power plant capacity or generation to come from renewable sources by a certain date.[12] However, most States are out of compliance with their own program due to issues with their RPS formulation, reporting mechanisms, monitoring, and exaction of penalties for non-compliance.[13] (Texas is the major exception.)
• Tax incentives directed toward solar generation originated with the Energy Tax Act of 1978 (Public Law 95-618), which established a business energy tax credit of 10 percent of investment in solar technologies. The business tax credit was extended periodically until passage of the Energy Policy Act of 1992. As part of the Energy Policy Act of 1992, it became a permanent 10 percent tax credit. Section 1335 of the Energy Policy Act of 2005 (EPACT2005)(Public Law 109-58) established a 30-percent personal tax credit, not to exceed $2,000 for the purchase of solar electric and solar water heating property. The Emergency Economic Stabilization Act of 2008 extended it to 2016 and lifted the $2,000 cap. The 2008 law allowed electric utilities to qualify. [14]
• The New Technology Credit , also known as the Production Tax Credit (PTC), was first introduced as part of the Energy Policy Act of 1992 (EPACT1992) (Public Law 102-486). The credit was defined as a 1.5-cents-per-kilowatthour (kWh) payment (adjusted annually for inflation), payable for 10 years, to private investors as well as to investor-owned electric utilities for electricity from wind power and closed-loop (dedicated crops) biomass facilities. The American Jobs Creation Act of 2004 (AJCA) (Public Law 108-357) expanded the PTC to include solar energy. However, the recipient of the credit had to choose one of the two credits (i.e. either the PTC or the ITC). The Energy Policy Act of 2005 (EPACT2005) (Public Law 109-58) made solar facilities placed into service after December 31, 2005, ineligible for the PTC. While solar was eligible for the PTC for a brief period, its impact on solar development was largely inconsequential. [15]

What Does Solar Cost?

• The Energy Information Administration assumes the total overnight capital cost of solar thermal technology to be $5,021 per kilowatt (in 2007 dollars).[16]
• The Energy information Administration calculates the levelized cost of generating technologies, which is the present value of the total cost of building and operating a generating plant over its financial life, converted to equal annual payments and amortized over expected annual generation. In 2016, the levelized cost of solar thermal is 26.37 cents per kilowatt hour (in 2007 dollars) and for solar photovoltaic, it is 50 percent higher, 39.57 cents per kilowatt hour. The costs for solar technologies are higher than that of natural gas combined cycle, whose costs are 7.99 to 8.39 cents per kilowatt hour. Pulverized coal and coal-fired integrated gasification combined cycle have levelized costs at 9.46 and 10.35 cents per kilowatt hour, respectively. EIA includes a 3-percentage point increase in the cost of capital when evaluating investments in greenhouse gas intensive technologies, such as these coal projects, which is equivalent to a $15 per ton carbon dioxide emission fee, and a 2 percentage point reduction in the cost-of-capital for eligible renewable technologies under the loan guarantee program of the Stimulus Act. [17]
• According to Houston-based Standard Renewable Energy, an installed residential solar system for a 2,100-square-foot-home would cost about $25,500. [18]

Land Mass

• For comparison purposes, the land mass and output of California’s Diablo Canyon Power Plant is compared to the land mass required to produce a similar quantity of electricity using solar power. The 2,200 megawatt nuclear facility requires 3 square kilometers, while a solar power station would require 687.5 square kilometers with a power density of 3 watts per square meter.[19]
• Examples of solar plants are the 14-megawatt Nellis solar facility in Nevada with some 70,000 panels and the 11-megawatt solar facility in Serpa, Portugal, with 52,000 panels. [20]

Texas

• Texas law requires that 5,880 megawatts of new renewable generation be built in the state by 2015, which will meet about 5 percent of the state’s projected electricity demand. The legislation also sets a cumulative target of installing 10,000 megawatts of renewable generation capacity by 2025. The measure also includes a requirement that the state must meet 500 megawatts of the 2025 target with non-wind renewable generation.[21]
• According to Houston-based Standard Renewable Energy, an installed residential solar system for a 2,100-square-foot-home would cost about $25,500. The existing federal incentives (the 30-percent ITC) would subsidize that cost by $7,650. In Austin, residents get an additional subsidy of $13,500, and in Dallas, they get approximately another $7,900. [22]
• The Texas legislature recently passed a measure to let homeowners finance their solar installations with help from the local government, and pay back the cost via extra property taxes over 20 years. [23]
• The staff of the Electric Reliability Council of Texas (ERCOT) with input from stakeholders estimated the costs and benefits of various generating technologies. The cost of solar photovoltaic was estimated at $314 per megawatt hour (about 8 times more than a coal-fired plant) and the cost of solar thermal was estimated at $169 per megawatt hours (over 4 times the cost of a coal-fired plant). These costs are approximate generation cost averages with many variable factors including capital costs, life expectancy, operation and maintenance, capacity factor and fuel costs. They exclude ancillary services costs and transmission impacts. [24]

California

• The California Energy Commission has estimated that its requirement of 33 percent renewables in 2020 will entail $5.7 billion in new 500 and 230 kV transmission lines alone, in addition to lower-voltage lines, substations, and reactive power supplies. The figure does not include lines associated with new or upgraded conventional generation.[25]
• In 2006, solar capacity in California was 402 megawatts, 0.6 percent of the state total capacity of 63,213 megawatts.[26]
• In 2007, California’s solar capacity produced 0.26 percent of the state’s electricity.[27]
• In 2008, California had the most installed photovoltaic panels that are tied to the power grid, and increased its share by 179 megawatts.[28]

International

• The U.S. ranks fourth in the world for cumulative installed solar electric power. Germany is first, Spain is second, and Japan is third. [29] In Germany, a feed-in tariff of 27 cents per kilowatt hour has produced an explosion in the use of solar photovoltaics. Under a feed-in tariff, electric utilities are obligated to purchase renewable electricity at a higher rate than retail, in order for the renewable technology to overcome price disadvantages. In Japan, the government has set a target for 30 percent of all households to have solar panels installed by 2030. [30] See the bullet below on Spain.
• The International Energy Agency is projecting solar capacity to reach 208 gigawatts by 2030, 2.7 percent of the total capacity projected for that year, generating one percent of the world’s electricity. In 2006, it generated 0.02 percent of the world’s electricity and represented 0.2 percent of the world’s capacity. [31]
• Britain has a European target of meeting 15 percent of its electricity demand in 2020 with renewable sources. Some government insiders feel the task is hopeless. The government’s own clean-energy advisers have warned that Britain could spend £100bn over the next decade and still not hit the target. The credit crunch slowed the already slow rate of renewable deployment to a crawl. Almost half the power generated in Britain comes from coal and a bit more than a third from natural gas. Nuclear power stations contribute 17 percent and wind provides 0.6 percent. [32] In 2007, solar PV provided 0.3 percent of the UK’s renewable generation capacity and 0.1 percent of its renewable electricity. [33]
• Spain has legislation that requires 20 percent of its electricity production to be from renewable energy by 2010. Spain’s National Energy Commission estimates that 2,945 megawatts of solar capacity were installed by year-end 2008, with 2,253 megawatts installed in 2008, making Spain the second-largest country for installed solar capacity. Solar energy generated less than 1 percent of Spain’s total electricity production in 2008 at a price per kilowatt hour that was over 7 times higher than the average price. To attract investors and make renewable energy profitable against other forms of energy, Spain found that renewable energy must be subsidized. Spain provides both regulated rates and direct incentives to attract investment and meet its policy goals. However, a Spanish university researcher found that the “green jobs” agenda that the Spanish Government has instituted, and to which the U.S. government now promotes, has, in fact, resulted in job loss elsewhere in the country’s economy. For each “green” megawatt installed, 5.28 jobs on average were lost in the Spanish economy, and for each megawatt of solar energy installed, 12.7 jobs were lost. Although solar energy may appear to employ many workers in the plant’s construction, in reality it consumes a great amount of capital that would have created many more jobs in other parts of the economy. [34] Recently, the Spanish Government decided to slash subsidies to solar power. The government will subsidize just 500 megawatts of solar projects this year, down sharply from 2,400 megawatts last year. [35]

[2] Energy Information Administration, Monthly Energy Review, Table 7.2a, http://www.eia.doe.gov/emeu/mer/pdf/pages/sec7_5.pdf

[3] Capacity found at Energy Information Administration, Electric Power Annual, http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile2_2.pdf for 2007 and preliminary 2008 data provided in an email from R. Schnapp, EIA, to M. Hutzler, IER, April 29, 2009; generation at Energy Information Administration, Monthly Energy Review, http://www.eia.doe.gov/emeu/mer/pdf/pages/sec7_5.pdf.

[4] Energy Information Administration, Annual Energy review 2007, Table 10.8, http://www.eia.doe.gov/emeu/aer/contents.html, and Energy Information Administration, Annual Energy Outlook 2009, Table A16, http://www.eia.doe.gov/oiaf/aeo/index.html .

[5] Energy Information Administration, Annual Energy Outlook 2009, Tables A8 and A16, SR-OIAF/2009-3, April 2009, http://www.eia.doe.gov/oiaf/aeo/index.html .

[6] Edison Electric Institute, Actual and Planned Transmission Investment by Shareholder-Owned Utilities, 2000-2009. http://www.eei.org/common/images/industry_issues/Energy_Data_Alert/bar_Transmission_Investment.jpg

[7] The Brattle Group, “Transforming America’s Power Industry: The Investment Challenge 2010-2030, November 2008, www.thebrattlegroup.org/_documents/UploadLibrary/Upload726.pdf

[8] Greenwire, Electricity: “Will Americans learn to love the ‘smart grid’?”, www.eenews.net/Greenwire/2009/02/27/archive/1?terms=smart+grid+cost .

[9] ClimateWire, “Renewable Energy: Pricey ‘supergrid’ seen as key to offshore wind power in Europe”, 2/9/09, www.eenews.net/climatewire/2009/02/09/1

[10] Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, http://www.eia.doe.gov/oiaf/servicerpt/subsidy2/pdf/execsum.pdf, Tables ES5 and ES6.

[11] General Accounting Office, Federal Electricity Subsidies, Oct. 2007, page 21, http://www.gao.gov/new.items/d08102.pdf

[12] Annual Energy Outlook 2009, Legislation and Regulations, Table 3, http://www.eia.doe.gov/oiaf/aeo/pdf/leg_reg.pdf.

[13] “A National Renewable Portfolio Standard: Politically Correct, Economically Suspect,” Robert J. Michaels, April 2008 Electricity Journal.

[14] Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, http://www.eia.doe.gov/oiaf/servicerpt/subsidy2/index.html, and American Solar Energy Society, http://www.ases.org/index.php?option=com_content&view=article&id=286&Itemid=58.

[15] Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, http://www.eia.doe.gov/oiaf/servicerpt/subsidy2/index.html .

[16] Energy Information Administration, Assumptions to the Annual Energy Outlook 2009, Table 8.2, http://www.eia.doe.gov/oiaf/aeo/assumption/index.html.

[17] Email from C. Namovicz, Energy Information Administration, to M. Hutzler, Institute for Energy Research, April 29, 2009.

[18] Houston Chronicle, “Solar power, Looking for ray of sunshine”, May 27, 2009, http://www.chron.com/CDA/archives/archive.mpl?id=2009_4744238 .

[19] Seth Myers, Energy Tribune with input from the Energy Information Administration and the Pacific Gas and Electric Co.

[20] Energy Information Administration, International Energy Outlook 2009, May 2009, http://www.eia.doe.gov/oiaf/ieo/pdf/0484(2009).pdf

[21] http://www.pewclimate.org/node/1303

[22] Houston Chronicle, “Solar power, Looking for ray of sunshine”, May 27, 2009, http://www.chron.com/CDA/archives/archive.mpl?id=2009_4744238 .

[23] Greenwire, Solar Power, June 1, 2009, http://www.eenews.net/Greenwire/2009/06/01/archive/10?terms=solar .

[24] Issues Associated with Renewable Energy in Texas, Informal White Paper for the Texas Legislature, Mar. 28, 2005, http://www.ercot.com/news/presentations/2006/RenewablesTransmissi.pdf

[25] California Energy Commission, Intermittency Analysis Project: Summary of Final Results, CEC 500-2007-081 (2007) at 26. http://www.energy.ca.gov/2007publications/CEC-500-2007-081/CEC-500-2007-081.PDF.

[26] http://www.eia.doe.gov/cneaf/solar.renewables/page/state_profiles/california.html

[27] Energy Information Administration, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sprdshts.html

[28] Reuters, U.S. installed solar capacity up 17 percent in 2008, March 20, 2009, http://www.reuters.com/article/rbssUtilitiesMultiline/idUSN2050533620090320 .

[29] Solar Energy Industries Association, http://www.seia.org/cs/about_solar_energy/industry_data .

[30] Energy Information Administration, International Energy Outlook 2009, May 2009, http://www.eia.doe.gov/oiaf/ieo/pdf/0484(2009).pdf .

[31] International Energy Agency, World Energy Outlook, November 2008.

[32] The Guardian, March 21, 2009, http://www.guardian.co.uk/environment/2009/mar/21/renewable-energy , and “Windmills flap helplessly as coal remains king”, February 18, 2009, http://business.timesonline.co.uk/tol/business/industry_sectors/natural_resources/article5755210.ece

[33] House of Lords, The Economics of Renewable Energy, HL Paper 195-I, November 25, 2008, http://www.publications.parliament.uk/pa/ld200708/ldselect/ldeconaf/195/195i.pdf.

[34] Study of the effects on employment of public aid to renewable energy sources, Universidad Rey Juan Carlos, March 2009, http://www.juandemariana.org/pdf/090327-employment-public-aid-renewable.pdf .

[35] Wall Street Journal, “Darker Times for Solar-Power Industry”, May 11, 2009, http://online.wsj.com/article/SB124199500034504717.html .

Coal-fired electricity generation is far cleaner today than ever before. The popular misconception that our air quality is getting worse is wrong, as shown by EPA’s air quality data. Modern coal plants, and those retrofitted with modern technologies to reduce pollution, are a success story and are currently providing about 50% of our electricity. Undoubtedly, pollution emissions from coal-fired power plants will continue to fall as technology improves.

Executive Summary

America’s improving air quality is an untold success story. Even before Congress passed the Clean Air Act Amendments of 1970, air quality had been improving for decades.[i] And since 1970, the six so-called criteria pollutants have declined significantly, even though the generation of electricity from coal-fired plants has increased by over 180 percent. [ii] (The “criteria pollutants” are carbon monoxide, lead, sulfur dioxide [SO₂], nitrogen oxides [NO_x], ground-level ozone, and particulate matter [PM]. They are called “criteria” pollutants because the EPA sets the criteria for permissible levels. [iii]) Total SO₂ emissions from coal-fired plants were reduced by about 40 percent between 1970 and 2006, and NO_x emissions were reduced by almost 50 percent between 1980 and 2006. On an output basis, the percent reduction is even greater, with SO₂ emissions (in pounds per megawatt-hour) almost 80 percent lower, and NO_x emissions 70 percent lower.

Figure 1 below shows the increases in Gross Domestic Product, vehicle miles traveled, energy consumption, and population since 1980, and it compares them to the decline in the aggregate emissions of criteria pollutants. Today, we produce more energy, drive further, and live more comfortably than we did in the past, all the while enjoying a cleaner environment.

Figure 1: EPA’s Comparison of Air Quality, Emissions, and Societal Trend

Source: http://www.epa.gov/airtrends/images/comparison.jpg

One factor in improving air quality has been the pollution-control technologies used by coal-fired power plants. Today’s coal-fired electricity generating plants produce more power, with less emission of criteria pollutants, than ever before. According to the National Energy Technology Laboratory (NETL), a new pulverized coal plant (operating at lower, “subcritical” temperatures and pressures) reduces the emission of NO_x by 86 percent, SO₂ by 98 percent, and particulate matter (PM) by 99.8 percent, as compared with a similar plant having no pollution controls [xv]. Undoubtedly, air quality will continue to improve in the future because of improved technology.

Today, coal-fired electricity generation produces nearly half of the electricity generation in America and provides many jobs. For example, Prairie State Energy Campus, a 1,600-megawatt coal plant under construction in southern Illinois, provides 1,200 people with jobs in around-the-clock construction. Between its power plant, coal mine, and other assets, the campus will inject some $2.8 billion into the Illinois economy, creating 2,300 to 2,500 temporary construction jobs and 500 permanent positions, while emitting 80 percent less in pollutants than most existing power plants.[iv] When completed, the power plant will deliver electricity to 2.4 million homes in at least nine states.

Background

• Even before Congress passed the Clean Air Act Amendments of 1970, creating the Environmental Protection Agency, air quality was improving. Prior to 1970, business saw certain types of pollution as waste, and worked to reduce them through technological improvements in order to increase efficiency. Furthermore, state and local policymakers worked to reduce pollution.[v]
• The Clean Air Act, last modified in 1990, requires the Environmental Protection Agency (EPA) to set National Ambient Air Quality Standards to control pollutants considered harmful to public health or the environment: these are the so-called criteria pollutants.
• Two of these pollutants, SO₂ and NO_x are the principal pollutants that cause acid precipitation (colloquially known as acid rain). SO₂ and NO_x emissions react with water vapor and other chemicals in the air to form acids that fall back to earth. Prior to controlling for these emissions, power plants produced most (about two-thirds) of the SO₂ emissions in the United States. The majority (about 50 percent) of NO_x emissions came from cars, buses, trucks, and other forms of transportation, with power plants contributing about 25 percent. The remainder came from other sources, such as industrial and commercial boilers.[vi]
• The 1990 changes to the Clean Air Act introduced a permanent cap on the total amount of SO₂ emissions that may be emitted by electric power plants nationwide, thereby reducing the level of these emissions in the atmosphere. The approach used was a cap-and-trade program with a steadily declining cap through 2010.
• In order to comply with the Clean Air Act Amendments of 1990, electric utilities could either switch to low sulfur coal, add equipment (e.g., scrubbers) to existing coal-fired power plants in order to remove SO₂ emissions, purchase permits from other utilities that exceeded the reductions needed to comply with the cap, or use any other means of reducing emissions below the cap, such as operating high-sulfur units at a lower capacity utilization.
• EPA devised a two-phased strategy to cut NO_x emissions from coal-fired power plants. The first phase, finalized in a rulemaking in 1995, aimed to reduce NO_x emissions by over 400,000 tons per year between 1996 and 1999. The second phase began in 2000, and it aimed to reduce NO_x emissions by over 2 million tons per year. The second phase reduction goal was exceeded, owing in part to additional state-initiated NO_x reductions in the Northeast.[vii]
• In 1998, EPA issued a rule that required 21 states and the District of Columbia to further reduce NO_x emissions through the use of newer, cleaner control strategies. The rule gave each affected state a NO_x emission target and let the state determine how to reduce its emissions. The goal was to reduce total emissions of NO_x by 1 million tons in the affected states by 2007. Most states were required to begin reductions in 2004.[viii]
• EPA issues air pollution control standards under the Clean Air Act Extension of 1970. These standards are called New Source Performance Standards (NSPS). EPA’s NSPS require all power plants for which construction commenced after February 28, 2005, to not exceed 1.0 lb/megawatt hour (0.11 lb/million Btu) of NO_x, 1.4 lb/megawatt hour (0.15 lb/million Btu) of SO₂, and 0.14 lb/megawatt hour (0.015 lb/million Btu) of particulate matter (PM). [ix] However, as can be seen below, most new plants are built to more stringent criteria.

Coal Industry Emissions Reduction

• Of the 328,720 megawatts of coal-fired capacity reporting their control technologies to the Energy Information Administration in 2005, 48 percent (158,493 megawatts) have cooling towers, 31 percent (101,338 megawatts) have flue gas desulfurization equipment (scrubbers), and 100 percent have particulate collectors.[x]
• The following graph compares the SO₂ and NO_x emissions from coal-fired power plants divided by the fuel consumed by these plants from 1970 to 2006. Between 1970 and 2006, SO₂ emissions in lbs per million Btu were reduced by almost 80 percent and NO_x emissions in lbs per million Btu were reduced by over 70 percent. Between 1970 and 2006, total SO₂ emissions were reduced by about 40 percent. Between 1980 and 2006, NO_x emissions were reduced by almost 50 percent.



• A study by the National Energy Technology Laboratory (NETL) compared the emission rates from pulverized coal plants and integrated gasification combined cycle plants based on the environmental regulations that would apply to plants built in 2010 using technology designs from several vendors, including General Electric Energy (GEE), ConocoPhillips (CoP), and Shell. These rates are provided in Table 1 for three criteria pollutants: sulfur dioxide, nitrogen oxides, and particulate matter (PM).[xi] The rates range from .0105 to .0848 lbs/million Btu for SO₂, .055 to .07 lbs/million Btu for NO_x, and .0071 to .013 lbs/million Btu for PM, depending on technology type. These emission rates are 43 to 93 percent lower than the current NSPS for SO₂, 36 to 50 percent lower than the current NSPS for NO_x, and 13 to 53 percent lower than the current NSPS for PM. Integrated gasification units have lower criteria pollutants than pulverized coal plants.

• According to NETL, for a new pulverized coal plant (subcritical) built in 2008, pollution controls reduce NO_x emissions 86 percent, SO₂ emissions by 98 percent, and PM by 99.8 percent when compared with a similar plant with no pollution controls. The target emission level for NO_x is 0.070 lb/MMBtu, for SO₂ is 0.085 lb/MMBtu, and for PM is 0.013 lb/MMBtu. Without control technologies, a subcritical coal plant would emit 0.5 lb/MMBtu of NO_x, 4.35 lb/MM Btu of SO₂, and 6.5 lb/MM Btu of PM.[xii] The figure below graphically depicts the criteria pollutants from a new controlled plant vs. a new uncontrolled plant.

Cost Factors in Emission Reductions

• According to the EIA, the costs of adding flue gas desulfurization (FGD) equipment to remove sulfur dioxide are, in 2006 dollars, $301/KW for a 300 MW plant, $230/KW for a 500 MW plant, and $190/KW for a 700 MW plant. The costs for selective catalytic reduction (SCR) equipment to remove nitrogen dioxides are $124/KW for a 300 MW plant, $108/KW for a 500 MW plant, and $98/KW for a 700 MW plant. The costs per megawatt of capacity decline with plant size.  FGD units are assumed to remove 95 percent of the SO₂ and SCR units are assumed to remove 90 percent of the NO_x.[xiii]
• The NETL study provides estimates of both the capital cost and the levelized cost of these technologies, which are given in Table 2 in 2007 dollars.[xiv] The levelized cost is the present value of the total cost of building and operating the plant over its economic life, converted to equal annual payments. The plant costs range from $1,549 to $1,977 per kilowatt for a 550 megawatt plant, with integrated gasification combined cycle technology having the higher costs. The 20-year levelized plant cost was computed using fuel prices from the Energy Information Administration’s Annual Energy Outlook 2007. The levelized plant costs range from 6.33 to 8.05 cents per kWh.

Source:  National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants, DOE/NETL-2007/1281,
http://www.netl.doe.gov/energy-analyses/pubs/Bituminous%20Baseline_Final%20Report.pdf

• NETL estimates that for a pulverized subcritical coal plant, the equipment to control NO_x, SO₂, and PM comprises $324/kW of the $1,549/kW plant cost (21 percent). At the request of IER, NETL estimated the cost of a subcritical pulverized coal plant without controls for criteria pollutants. The levelized cost of the new controlled plant is 6.4 cents per kWh and that of the new uncontrolled plant is 5.2 cents per kWh, 19 percent lower. A controlled plant has slightly lower output, less than 1 percent lower, and its capital costs are about 25 percent higher due to the cost of the control technologies.[xv]

Coal-fired electricity generation is far cleaner today than ever before. The popular misconception that our air quality is getting worse is wrong, as shown by EPA’s data.[xvi] Modern coal plants, and those retrofitted with modern technologies to reduce pollution, are a success story and are currently providing about 50% of our electricity. Undoubtedly, pollution emissions from coal-fired power plants will continue to fall as technology improves.

Cap-and-Trade: “Acid Rain” versus Greenhouse Gases

The results of using a cap-and-trade system to fight “acid rain” have led some to argue that it is a model for efforts to reduce carbon dioxide emissions. But the analogy fails. Stark differences exist between the “acid rain” emission-reduction program and the challenge of reducing carbon dioxide, a natural byproduct of combustion, emitted by natural and man-made sources.

Carbon dioxide is emitted in the U.S. by hundreds of millions of sources, including every personal automobile, the appliances many of us use to cook our food and heat our homes, and the businesses upon which we depend for our livelihoods, to name a few. The “acid rain” emission reduction program was initially limited to 110 site-specific utility plants, and then later expanded to 445 plants.[xvii] In addition, carbon dioxide is a world-wide byproduct of combustion, whereas all criteria pollutants are local or regional. In other words, what the United States did for SO₂ and NO_x directly affected air quality here, while national action to limit carbon dioxide emissions will have little bearing on aggregate global emissions.

Furthermore, at the time of the SO₂ and NO_x reduction program, alternative low sulfur coal sources existed and utilities had available affordable and proven technologies to utilities to reduce their emissions. When Congress passed the Clean Air Act Amendments of 1990, therefore, coal-fired utilities could responsibly reduce emissions from their plants using various options that limited cost impacts to the consumer.

In addition, attempts to extrapolate the “acid rain” success story to the challenge of reducing carbon dioxide emissions fail to recognize the history of similar programs in other parts of the world. For example, the “Emissions Trading Scheme” of the European Union has been ineffective at reducing carbon dioxide emissions at the same time it has increased prices and harmed businesses and consumers.[xviii] Further, the EU program has enriched some companies and industries at the expense of consumers.

A recent study by Laurie Williams and Allen Zabel, career employees of the Environmental Protection Agency, makes these points about what the authors call the “Acid Rain Myth.”[xix] As the authors explain, that those who champion the use of cap-and-trade to address global warming ignore the crucial distinctions between the issues we faced in 1990 with acid rain and the issues we face today with global warming.

The following highlights Williams and Zabel’s study demonstrate that the experience of the acid rain program cannot and should not be compared to cap and trade for greenhouse gas emissions:

• “Most importantly, the success of the Acid Rain program did not depend on replacing the vast majority of our existing energy infrastructure with new infrastructure in a relatively short time. Nor did it depend on spurring major innovation. Rather, the Acid Rain program was successful as a mechanism to guide existing facilities to undertake a fuel switch to a readily available substitute, the low sulfur coal in Wyoming’s Powder River Basin.”
• “The goal of the Acid Rain program was to reduce sulfur dioxide emissions, while keeping the cost of energy from coal low. To be effective, climate change legislation must do the opposite; it must gradually increase the relative price of energy from coal and other fossil fuels to create the appropriate incentives for both conservation and the scale-up of clean energy.”
• “Further, the Acid Rain program did not allow any outside offsets and so provides no basis for the widespread assumption that an offset program will help with climate change. In addition, the success of the program was aided by the low, competitive price of low-sulfur coal.”
• “According to Professor Don Munton, author of ‘Dispelling the Myths of the Acid Rain Story’ the impact of the program has been overstated: The potential for a massive switch to low sulfur coal was no secret. Such coal was cheap and available, and it became cheaper and more available throughout the 1980s. Indeed, low-sulfur coal became very competitive with high-sulfur supplied well before the Clean Air Act became law.”

In short, the mechanisms available to reduce pollutants allowed for more generation of energy with less pollution. But this success cannot be extrapolated to the regulation and reduction of carbon dioxide, a much more challenging undertaking. None of the conditions existing at the time of the apparent success of the SO₂ and NO_x reduction program apply to carbon dioxide, and, in any case, unilateral action by the United States will have little impact upon global carbon dioxide concentrations. Indeed, the challenges presented by the control and regulation of carbon dioxide have no parallels in the history of emission regulation.

[xi] National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants, DOE/NETL-2007/1281,

http://www.netl.doe.gov/energy-analyses/pubs/Bituminous%20Baseline_Final%20Report.pdf

[xii] Ibid.

[xiii] Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, Table 44, http://www.eia.doe.gov/oiaf/aeo/assumption/electricity.html

[xiv]Ibid.

[xv] Email from J. Kukielka ,NETL to M. Hutzler, IER, January 9, 2009.

[xvi] Environmental Protection Agency, Air Trends, http://www.epa.gov/airtrends/.

[xvii] Kenneth P. Green et. al, Climate Change: Caps vs. Taxes, American Enterprise Institute, (June 2007) http://www.aei.org/publications/filter.all,pubID.26286/pub_detail.asp

[xviii] See European Union, Emissions trading: 2007 verified emissions from EU ETS businesses, May 23, 2008, http://europa.eu/rapid/pressReleasesAction.do?reference=IP/08/787&format=HTML&aged=0&language=EN&guiLanguage=en

[xix] Keeping Our Eyes on the Wrong Ball, 2/21/09, http://www.carbonfees.org/home/Cap-and-TradeVsCarbonFees.pdf

Titusville, Pennsylvania. While historical records indicate that naturally occurring seeps of petroleum were collected and used for a variety of purposes as early as the 1600s, Colonel Edwin Drake was the first to devise a mechanical system to drill into underground reservoirs and secure sufficient quantities of petroleum to make it commercially marketable.
Source: http://www.eia.doe.gov/neic/infosheets/petroleumproductsconsumption.html

What was the first commercially marketed use of petroleum in the U.S.?

Medicine.  Early settlers of northwestern Pennsylvania skimmed petroleum from streams and used it medicinally.  Impressed by the apparent benefits of petroleum as a medicine, about 1849, Samuel Kier, a shipper and merchant, began bottling the petroleum he collected from salt wells on his father’s land and marketed it as a cure for all sorts of human and animal ailments.
Source: http://www.pabook.libraries.psu.edu/palitmap/bios/Kier__Samuel_Martin.html

How much crude oil is supplied to U.S. refineries each day?

In 2007, total refinery input of crude oil averaged 15 million barrels per day.
Source: Energy Information Administration, Annual Energy Review2007, Table 5.8, page 139.

How much of the crude oil/petroleum America uses annually comes from foreign sources?

In 2007, approximately 65% of the crude oil/petroleum used in the U.S. was imported.
Source: Energy Information Administration, Annual Energy Review 2007, Table 5.1, page 125.
Please note that the 65% number is for gross imports. If net imports were used as the numerator, the percentage would be 58%.

How much of the crude oil/petroleum America uses annually is produced within the U.S.?

In 2007, approximately 35% of the crude oil/petroleum used in the U.S. was produced domestically.
Source: Energy Information Administration, Annual Energy Review 2007, Table 5.1, page 125.

The following are the top U.S. producers of crude oil.  Which state produces the most?

The top crude oil-producing state in the U.S. is Texas, followed in order by Alaska, California, Louisiana, and Oklahoma.
Source: http://tonto.eia.doe.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm

How many barrels of oil does the world consume every day?

In 2007, the world consumed 85.8 million barrels of oil every day.  That is about 42,000 gallons per second!
Source: Energy Information Administration, Short-term Energy Outlook Sept. 2008, Table 3a.

How many refineries are there in the U.S.?

There are currently 149 U.S. refineries owned by 54 companies in 33 states, with total crude oil processing capacity at roughly 17 million barrels per day.
Source: Energy Information Administration, Annual Energy Review 2007, Table 5.9, page 141 and http://tonto.eia.doe.gov/state/state_energy_profiles.cfm?sid=HI

When was the last U.S. oil refinery built?

The last new U.S. refinery was constructed in 1976.
Source: Andrew P. Morriss, Engage, Vol. 8, No. 3, pp. 4-13

How much of the gasoline consumed in the U.S. is produced by U.S. refineries?

U.S. refineries produce 90% of the gasoline Americans consume. The remaining 10% of finished gasoline and gasoline additives is imported.
Source: Energy Information Administration, Short Term Energy Outlook Sept. 2008, Table 4a.

Refineries are owned by large, integrated oil companies as well as independent companies.  What percentage of refinery capacity does the largest U.S. refiner control?

The largest U.S. refiner controls just 13% of U.S. refining capacity.
Source: http://en.wikipedia.org/wiki/List_of_oil_refineries#United_States, and Energy Information Administration, Annual Energy Review 2007, Table 5.9, page 141.

A barrel of crude oil equals 42 gallons.  How many gallons of gasoline result from refining a barrel of crude oil?

On average, about 20 gallons of gasoline can be produced from a barrel of crude oil.  Gasoline represents about 47% of the yield from a refined barrel of crude.
Source: http://www.eia.doe.gov/kids/energyfacts/sources/non-renewable/oil.html#How%20used

What is the most significant factor affecting the price of gasoline?

The cost of crude oil is the single greatest factor affecting the price of a gallon of gasoline.  The Energy Information Administration estimates that, in August 2008, the national average retail price of a gallon of gasoline was $3.78 and the cost of crude oil represented 73% of that price.  Taxes constituted another 11%, distribution and marketing 10%, and refining 6%.
Source: http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp

What portion of the average consumer’s transportation budget is spent on gasoline (and motor oil)?

According to the Bureau of Labor Statistics, in 2004, the average consumer spent 20% of their transportation budget on gasoline and motor oil.
Source: http://www.bls.gov/cex/csxann04.pdf

How much do Federal and state taxes add to the price of a gallon of finished gasoline?

In August 2008, Federal and state taxes made up about 11% of the price of a gallon of gasoline.
Source: http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp

How much do all sources of “renewable energy” (wind, solar, biomass, hydropower, geothermal) contribute to meeting total U.S. energy needs?

The Energy Information Administration estimates that, in 2007, renewable energy supplied 7% of total U.S. energy needs.  Fossil fuels and nuclear power provided 93% of the energy used by Americans.
Source: Energy Information Administration, Annual Energy Review 2007, Table 1.3, page 9.

How much has the U.S. refining industry spent over the last 10 years on environmental improvements to their facilities and processes?

The U.S. refining industry has spent  $54.5 billion over the last 10 years on making environmental improvements, much of it to make cleaner fuels.
Source: http://www.api.org/ehs/performance/upload/ENVIRON_EXPEND_REPORT.pdf

What is the greatest source of crude oil and petroleum products found in U.S. waters?

The vast majority (63%) of petroleum found floating in oceans, rivers, streams, and lakes comes from oil seeping naturally out of the ocean floor, lake beds, and the land.  Spills caused by petroleum users such as improperly discarded motor oil, gasoline spilled during fueling, leaky petroleum storage tanks, and even fuel leaking from pleasure boat engines are responsible for about 33% of petroleum in U.S. waters.  Only 4% of oil spills result from the exploration, production and transportation of crude oil and refined petroleum products. Data are for 1990-1999.
Source: http://www.eia.doe.gov/kids/energyfacts/sources/non-renewable/oil.html#Environment

What percentage of retail gasoline outlets/service stations are owned and operated directly by the large, integrated oil companies?

Large, integrated oil companies control only 10% of the Nation’s retail gasoline service stations.  About 90% of gas stations in the U.S. are owned by non-integrated companies and individuals.  Individual service stations may bear the logo of a major petroleum company, but they are typically owned by franchisees – people who purchase the right to market and sell a company’s name-brand products, just like people who invest in a 7-11 or McDonald’s.
Source: http://www.api.org/aboutoilgas/sectors/marketing/index.cfm#q12

How much of the nation’s refining capacity is controlled by the four largest U.S. refining companies?

In 2003, the four largest U.S. refining companies controlled a little more than 40% of refining capacity.  In contrast, the top four companies in the auto manufacturing, brewing, tobacco, floor coverings, and breakfast cereals industries controlled between 80% and 90% of their markets.
Source: http://www.eia.doe.gov/neic/rankings/refineries.htm

Of the industry sectors listed below, which has the largest earnings profit margin?

For the 2rd quarter of 2008,  the pharmaceutical and medicine industry  reported making an estimated 26.3 cents in earnings per dollar of sales.  Oil and natural gas industry earnings, at about 6.8 cents per dollar of sales, were the lowest among these industry sectors.
Source: http://www.api.org/statistics/earnings/upload/earnings_perspective.pdf

Most crude oil and petroleum products are transported at some point by pipelines.  How many miles of pipelines are there in the U.S.?

There are a whopping 2.3 million miles of pipelines crisscrossing the U.S.  If all these pipelines were laid end to end, they would circle the Earth a little more than 92 times!
Source: http://www.phmsa.dot.gov/portal/site/PHMSA

How many barrels of petroleum does a typical modern ocean-going supertanker hold?

“Supertankers” are generally defined as those greater than 250,000 tonnes deadweight (meaning the maximum weight they can carry when fully loaded).  Today’s supertankers, on average, can carry about 2 million barrels or 84 million gallons of crude oil and petroleum product.  The largest supertanker in the world is the Norwegian-owned Knock Nevis which is 647,955 tonnes deadweight and can hold 4.1 million barrels of petroleum.
Source: http://www.eia.doe.gov/emeu/cabs/Saudi_Arabia/pdf.pdf

• In 2008, wind represented 0.5% of all energy consumed in the US.[1]

• In 2008, wind represented 1.3% of all electricity generated in the US.[2]

• In 2008, wind generating capacity in the U.S. totaled 25,170 megawatts and generated 52.0 million megawatt hours.[3] Wind turbines generated only a percentage of their theoretical maximum output due to their intermittency (the wind does not always blow).
• Due to incentives in the stimulus and to state mandates highlighted below, the Energy Information Administration (EIA) projects wind capacity to increase to 39.7 gigawatts by 2010, 66.6 gigawatts by 2020, and 68.1 gigawatts by 2030. Generation from wind is projected to increase to 112.1 billion kilowatt hours by 2010, 203.5 billion kilowatt hours by 2020, and 207.8 billion kilowatt hours by 2030. This level of projected wind generation in 2030 represents 4.1 percent of total U.S. electricity generation. The tapering off of new wind facilities after 2020 indicates that the development of the most economic sites with the best wind resources has occurred in EIA’s representation by 2020, making wind more expensive to site and construct after 2020. Thus, it will be more difficult for wind to compete with traditional technologies due to increased costs of less accessible sites and/or less wind resource availability. See EIA’s levelized costs for wind in 2016 below compared to other generating technologies. [5]

• The U.S. Department of Energy’s Energy Efficiency and Renewable Energy (EERE) report “20% Wind Energy by 2030” (2008) envisioned production that is over 7 times more than the generation level that EIA is projecting.[6] This would require, according to the DOE, 280 gigawatts of new wind capacity (or almost 13,000 megawatts of new wind turbines) each year. This growth level is equivalent to adding about half of the total installed wind capacity in the U.S. in 2008 each and every year through 2030. This growth in wind turbine capacity would require siting wind units on publicly owned lands where a large percentage of the development sites are located, continued taxpayer-funded subsidies, the building of power lines to remote areas where wind turbines are located, and the public acceptance of noise and other wind-related effects. Since wind is intermittent, the wind capacity would also need to be backed-up with reliable capacity, most likely from fossil fuels, adding additional cost and reducing the carbon dioxide benefits of introducing this level of wind energy. The DOE analysis is also predicated on the assumption of very high capacity factors for wind of more than 40 percent. The experience of wind in Texas highlighted below does not support capacity factors at that level, although such technology is improving (along with the technology of conventional energies).[7]

• Because wind power is available a relatively small fraction of the time, typical statements about how a wind unit can produce enough electricity to serve a large number of homes are misleading.[8] Since a wind unit cannot supply power continuously or even upon customer demand due to intermittency, dispatchable generators (usually fossil-fuel) are required to provide back-up power to the system to maintain reliability.[9] Wind on average serves fewer homes than advertised, and on hot summer days wind can serve far fewer still.

U.S. Transmission Statistics

• Total spending on new transmission by all investor-owned utilities in 2006 [current dollars] was $6.9 billion.[10] This figure underestimates total transmission spending since it excludes government-owned utilities and cooperatives.
• According to a November 2008 study by Brattle Group, total investment in transmission and distribution through 2030 is expected to total $880 billion, where $298 billion would be for transmission and $582 billion would be for distribution. The figure includes integration of 214 gigawatts of new generating capacity of which 39 gigawatts is for renewable technologies required under existing state renewable portfolio standards, continued installation of a “smart grid”, accommodation for new end-use technologies such as plug-in hybrid electric vehicles, and bringing new efficiencies and service options to end use customers. The authors caution that the figure could be an underestimate since it is derived from shareholder-owned electric utility expenditure data that excludes investments made by electric cooperatives and Government-owned utilities.[i]
• There is no standard definition of a “smart grid”. It generally refers to technologies that: 1) provide customers with information and tools that allow them to be responsive to system conditions, 2) ensure more efficient use of the electric grid, and 3) enhance system reliability. The latest federal stimulus law provides $11 billion for smart grid technology, including $4.5 billion for smart-technology matching grants.[ii] The $11 billion is a small percentage of what’s needed to get to the $880 billion mark, and that amount does not support a 20 percent renewable scenario by 2030.
• In Europe, it is estimated that 1.2 trillion Euros ($1.55 trillion) would be needed to build a super grid that captures offshore wind, hydropower, and solar panel arrays.[iii] It would require a new network of cables and interconnectors to bring offshore generated electricity to land and modernization of the onshore grid to deal with sudden changes in supply and demand and clear bottlenecks. It would also allow countries to export electricity at times of surplus wind generation and import from other green power sources. Currently, Denmark exports its surplus wind power free to Germany and Norway and imports coal-powered electricity from Germany.
• A report prepared by organizations responsible for electricity-system reliability in roughly half the states in the U.S. indicates that it would cost $100 billion to build a transmission system, including 15,000 circuit miles of extremely high voltage lines, that would move power from the Midwest and Great Plains, where most of the wind resources are located to big cities along the East Coast. They also estimate that building the wind turbines would cost about $720 billion. The report was prepared by the Midwest Independent System Operator, SERC Reliability Region, PJM Interconnection LLC, the Southwest Power Pool, the Mid-Continent Area Power Pool, and the Tennessee Valley Authority.[iv]

U.S. Wind Subsidies

• The Energy Information Administration estimates that total Federal subsidies for electric production for fiscal year 2007 from wind power are $23.37 per megawatt hour, compared to 44 cents for traditional coal, 25 cents for natural gas and petroleum liquids, 67 cents for hydroelectric power, and $1.59 for nuclear.[11] For wind power, these subsidies include a production tax credit of 2.0 cents per kilowatt-hour.[12] However, they do not include accelerated depreciation, (a five-year write-off), a favorable accounting treatment that wind developers receive. (Figures are in 2007 dollars.)

• According to the General Accounting Office, in fiscal year 2007, wind received 2.8 percent of all federal research subsidies to power generation but produced only 0.4 percent of U.S. electricity. Per kilowatt-hour, this was 14.7 times higher than the amount allocated to coal, most of which was spent to develop cleaner technologies. Coal produced 51.4 percent of all U.S. electricity in fiscal year 2007.[13]

• Approximately nine percent of electricity generated is lost in its transmission and distribution from power plants to end-use consumers (also called “line losses”).[14] Given that the production tax credit for wind is based on electricity generated, not sold, the PTC is actually costing taxpayers and consumers more than its current value (since 1/1/09) of 2.1 cents per kilowatt-hour since one-tenth of that electricity is not reaching consumers. Also, wind is an inefficient user of transmission because capacity must be available to handle the full rated output of turbines but wind turbines run at full capacity only a small portion of time.

U.S. Policies Affecting Wind

• While no federal renewable portfolio standard (RPS) exists, 28 states and the District of Columbia have a renewable portfolio standard mandating a certain percentage of a utility’s power plant capacity or generation to come from renewable sources by a certain date.[15] However, most States are out of compliance with their own program due to issues with their RPS formulation, reporting mechanisms, monitoring, and exaction of penalties for non-compliance.[16] (Texas is the major exception.) Wind is the technology that generally benefits the most from an RPS since it has lower costs than many other renewable generating technologies, particularly when subsidies are included.
• The federal production tax credit (PTC) for wind was first introduced as part of the Energy Policy Act of 1992. It was defined as a 1.5-cents-per-kilowatthour payment (adjusted annually for inflation), available for 10 years to investors for facilities placed in service between 1994 and June 30, 1999. The PTC for wind has expired and been reinstated several times since its origination. The Emergency Economic Stabilization Act of 2008 (Public Law 110-343) signed on October 3, 2008 extended the PTC to 2.1-cents-per-kilowatt-hour through 2012. The $787 billion economic stimulus President Obama signed into law in February 2009 makes a 30 percent investment tax credit available in lieu of the production credit.[17]

What Does Wind Cost?

• The Energy Information Administration assumes the total overnight capital cost of an onshore wind turbine to be $1,923 per kilowatt (in 2007 dollars) and that of an offshore wind unit to be $3,851 per kilowatt.[18] These costs are similar to the estimated cost made by the National Association of Manufacturers (NAM) and the American Council for Capital Formation (ACCF) of $2,000 per kilowatt for onshore units and $3,800 per kilowatt for offshore units (in 2008 dollars).[19].
• The Energy information Administration calculates the levelized cost of generating technologies, which is the present value of the total cost of building and operating a generating plant over its financial life, converted to equal annual payments and amortized over expected annual generation. In 2016, the levelized cost of onshore wind is 14.15 cents per kilowatt hour (in 2007 dollars) and for offshore wind, it is 22.96 cents per kilowatt hour. These values do not include the production tax credit since it is slated to expire at the end of 2012. The cost for onshore wind is higher than that of natural gas combined cycle, whose costs are 7.99 to 8.39 cents per kilowatt hour. Pulverized coal and coal-fired integrated gasification combined cycle have levelized costs at 9.46 and 10.35 cents per kilowatt hour, respectively. EIA includes a 3-percentage point increase in the cost of capital when evaluating investments in greenhouse gas intensive technologies, such as these coal projects, which is equivalent to a $15 per ton carbon dioxide emission fee, and a 2 percentage point reduction in the cost-of-capital for eligible renewable technologies under the loan guarantee program of the Stimulus Act.[20]
• All estimates of the potential cost per kilowatt hour of electricity are based on assumptions. Three important assumptions are (a) projected useful life of the generating unit, (b) the unit’s capacity factor over the projected useful life, and (c) operating and maintenance and replacement costs during the useful life. These factors are particularly important in the case of wind turbines because most wind turbines now being installed have relatively little operating history – often less than 5 years. If, for example, a per kilowatt hour cost estimate assumed a 20 year useful life and the actual useful life turned out to be only 10 years, the ACTUAL cost per kilowatt hour for that unit would be nearly double the original cost estimate.
• A report by the Lawrence Berkley laboratory sampled recently built wind units in the United States. Among the sample of projects built in 2007, reported installed costs ranged from $1,240/kilowatt to $2,600/kilowatt, with an average cost of $1,710/kilowatt.[21]

Climate and Land Mass

• If ten percent of the nation’s power is produced by renewable energy through a renewable electricity standard (RES), Resources for the Future estimated that the RES would reduce electricity’s carbon emissions by approximately 6 percent in 2020. Wind is estimated to represent 28 percent, geothermal 24 percent, and biomass 43 percent of the 10 percent of qualifying renewables. Coal-burning generators that emit the most carbon will be base-loaded and operate most of the time, supplying 48 percent of total generation, while production by lower-emitting gas-fired units will be partially replaced by the increased renewable generation and vary production to make up for wind’s intermittency.[22]

• For comparison purposes, and taking into account capacity (or load factors), the land area covered by a wind power station of the same energy output as a nuclear power station would be about 2,000 times as great (or an area of land 20km by 25km would be covered by wind turbines to produce the same electrical output as one nuclear power station occupying an area of land 500m square).[23]

Texas

• In 2008, wind capacity in Texas was 7,116 megawatts.[24]

• Texas leads the nation in wind capacity having 28% of the total wind capacity in the US. [25]

• Texas law requires that 5,880 MW of new renewable generation be built in the state by 2015, which will meet about 5 percent of the state’s projected electricity demand. The legislation also sets a cumulative target of installing 10,000 MW of renewable generation capacity by 2025. The measure also includes a requirement that the state must meet 500 MW of the 2025 target with non-wind renewable generation.[26]
• Frequently, estimates for wind energy include only turbine construction and maintenance, leaving out transmission, grid connection and management, and backup generation. One study estimates that direct subsidies, tax breaks, and increased production and ancillary costs associated with wind energy could cost Texas electric customers more than $4 billion per year and at least $60 billion through 2025.[v]

• In 2007 (the most recent year available), wind represented 4.4 percent of the state’s total capacity of 101,938 megawatts, yet wind produced only 2.2 percent of the state’s electricity that year.[27]

• The average output of wind turbines during Electric Reliability Council of Texas (ERCOT) system peaks (from 4 pm to 6 pm in July and August) was 16.8 percent of capacity. However, for any hour during these months, the output of the wind turbines could range from zero to 49 percent of installed capacity.[28] Because the use of an average number would be too optimistic due to the intermittency of wind, ERCOT assigns 8.7 percent of the installed capacity of wind turbines to its calculation of the ERCOT peak capacity reserve margin, based on a study of the effective load serving capability of wind.[29]

• The estimated cost for building transmission capacity in ERCOT to support new wind farms in the Competitive Renewable Energy Zones is $2.95 billion for the lowest cost plan (for 12 gigawatts) and from $3.78 billion to $6.38 billion for expandable plans, supporting 12 gigawatts of new wind capacity at the low cost end and 25 gigawatts at the high cost end of the range. Figures are as of 4/15/08.[30]

California

• The California Energy Commission has estimated that its requirement of 33 percent renewables in 2020 will entail $5.7 billion in new 500 and 230 kV transmission lines alone, in addition to lower-voltage lines, substations, and reactive power supplies. The figure does not include lines associated with new or upgraded conventional generation.[32]
• In 2008, wind capacity in California was 2,517 megawatts.[33]
• In 2007 (the most recent year available), California’s wind capacity represented 3.6 percent of its total generating capacity of 63,813 megawatts. It produced 2.6 percent of the state’s electricity that year.[34]
• In 2008, California’s wind capacity was third in the nation with 10 percent of the total wind capacity in the US. [35]
• During August, 2007, the highest five percent of load hours in California almost all had wind production levels below 600 megawatts and most were even below 200 megawatts, less than 8 percent of its capacity. Regarding the most critical hours, in 75 percent of the year’s top 20 load hours, wind production was at or under 150 megawatts, and the highest figure achieved in any of those 20 hours was just over 450 megawatts. Only in one of the twenty hours of highest load during the summer of 2007 did the actual hourly wind production exceed the net qualifying capacity, which is the amount of a resource’s capacity that can be counted for resource adequacy compliance filings.[vi]

International

• According to the Global Wind Energy Council, world installed capacity for wind in 2008 was 120,798 megawatts, increasing 29 percent from 2007 levels. The U.S. leads the world in wind generating capacity, with 20.8 percent (25,170 megawatts) of the world total, Germany is second with 19.8 percent (23,903 megawatts), and Spain is third with 13.9 percent (16,754 megawatts).[vii]
• The European Union generated 3.7 percent of its electricity from wind in 2007.[viii]
• According to the International Energy Agency’s energy statistics, the world generated 130 terawatt hours in 2006 from wind capacity totaling 74 gigawatts. Assuming all the units were on-line for the entire 2006 year results in a 20 percent capacity factor.[ix] Since not all units were constructed and operating at the beginning of 2006, the capacity factor would be higher. An earlier study, with mostly data for 2005, indicated world capacity was 59,010 megawatts with a capacity factor of 19.6 percent.[36]
• France, in 2008, had 3.4 gigawatts of capacity and generated 5.6 terawatt hours of electricity at a capacity factor of 24 percent. It ranked 7^th internationally in wind capacity with 2.8 percent of the world’s total.[x]
• Denmark, a country with over 6,000 wind turbines, many offshore, finds that it needs to import electricity due to the intermittency of its wind generating units and export the wind power. In 2003, 84 percent of western Denmark’s wind-generated electricity was exported at a revenue loss. Denmark’s conventional power plants are generally run at full capacity backing-up their wind units. When the wind does blow, the wind power is usually surplus and exported to other countries at a discounted price.[37] In 2008, Denmark had 3.18 gigawatts of wind power, 2.6 percent of world capacity, ranking 9^th overall.[xi]
• Britain has a European target of meeting 15 percent of its electricity demand in 2020 with renewable sources. Some government insiders feel the task is hopeless. The government’s clean-energy advisers have warned that Britain could spend £100bn over the next decade and still not hit the target. The credit crunch slowed the already slow rate of renewable deployment to a crawl. With financing and debt harder to come by, expensive offshore wind farms such as the London Array look less attractive to the big utilities.[xii] Almost half the power generated in Britain comes from coal and a bit more than a third from natural gas. Nuclear power stations contribute 17 percent and windmills provide 0.6 percent. Although the UK has built, with enormous subsidy, enough wind turbines to generate 5 percent of its electricity, no more than 1 percent is operational when needed since it is not operational during periods of intense heat or cold.[xiii] IN 2008, the UK had 3.24 gigawatts of wind capacity, 2.7 percent of the world total, and ranked 8^th overall.[xiv]
• Spain has legislation that requires 20 percent of its electricity production to be from renewable energy by 2010. The Government’s Renewable Energy Plan expects to have 20,155 megawatts of wind capacity by 2010. Spain’s National Energy Commission estimates that 15,617 megawatts of wind capacity was installed by year-end 2008, 77 percent of the 2010 target, making Spain the third-largest country for installed wind capacity. In 2008, wind energy provided 10.2 percent of the country’s electric consumption at a price per kilowatt hour that was almost 50 percent higher than wind’s generating price 10 years prior, partly due to high premiums in the regulated rates for renewable energy and the requirement that all renewable energy be purchased by electricity retailers. To attract investors and make renewable energy profitable against other forms of energy, Spain found that renewable energy must be subsidized. Spain provides both regulated rates and direct incentives to attract investment and meet its policy goals. However, a Spanish university researcher found that the “green jobs” agenda that the Spanish Government has instituted, and to which the U.S. government now promotes, has, in fact, resulted in job loss elsewhere in the country’s economy. For each “green” megawatt installed, 5.28 jobs on average were lost in the Spanish economy, and for each megawatt of wind energy installed, 4.27 jobs were lost.[xv]

[2] Energy Information Administration, Monthly Energy Review, Table 7.2a, http://www.eia.doe.gov/emeu/mer/pdf/pages/sec7_5.pdf

[3] Capacity found at http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html; generation at Energy Information Administration, Monthly Energy Review, http://www.eia.doe.gov/emeu/mer/pdf/pages/sec7_5.pdf.

[5] Energy Information Administration, Annual Energy Outlook 2009, Reference Case Tables A8 and A16, http://www.eia.doe.gov/oiaf/aeo/index.html .

[6] DOE, EERE, “20% Wind Energy by 2030”, July 2008, http://www1.eere.energy.gov/windandhydro/pdfs/41869.pdf

[7] “U.S. DOE Report “20% Wind Energy by 2030” Presents Implausible Scenario,” http://www.windaction.org/releases/16239 .

[8] Glenn R. Schleede, “False Claims about homes served by electricity from wind”, February 4, 2009.

[9]Electricity Reliability Council of Texas, http://www.ercot.com/news/presentations/2006/RenewablesTransmissi.pdf

[10] Edison Electric Institute, Actual and Planned Transmission Investment by Shareholder-Owned Utilities, 2000-2009. http://www.eei.org/common/images/industry_issues/Energy_Data_Alert/bar_Transmission_Investment.jpg.

[11] Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, http://www.eia.doe.gov/oiaf/servicerpt/subsidy2/pdf/chap5.pdf, Table 35

[12] Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, page 160, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/renewable.pdf

[13] General Accounting Office, Federal Electricity Subsidies, Oct. 2007, page 21, http://www.gao.gov/new.items/d08102.pdf

[14] Energy Information Administration, Annual Energy Review 2007, page 62, http://www.eia.doe.gov/emeu/aer/pdf/pages/secnote2.pdf .

[15] Annual Energy Outlook 2009, Legislation and Regulations, Table 3, http://www.eia.doe.gov/oiaf/aeo/pdf/leg_reg.pdf.

[16] “A National Renewable Portfolio Standard: Politically Correct, Economically Suspect,” Robert J. Michaels, April 2008 Electricity Journal.

[17] Energy Information Administration, Federal Financial Interventions and Subsidies in Energy Markets 2007, http://www.eia.doe.gov/oiaf/servicerpt/subsidy2/index.html; Energy Information Administration, Annual Energy Outlook 2009, Legislation and Regulations, http://www.eia.doe.gov/oiaf/aeo/pdf/leg_reg.pdf; and E&ENews, Wind Power: Industry boosters still blustery, even in a recession, April 13, 2009, http://www.eenews.net/eenewspm/2009/04/13.

[18] Energy Information Administration, Assumptions to the Annual Energy Outlook 2009, Table 8.2, http://www.eia.doe.gov/oiaf/aeo/assumption/index.html.

[19] American Council for Capital Formation/National Association of Manufacturers Study of the Economic Impact of the Lieberman-Warner Climate Security Act, http://www.accf.org/nam.html .

[20] Email from C. Namovicz, Energy Information Administration, to M. Hutzler, Institute for Energy Research, April 29, 2009.

[21] U.S. Department of Energy, Energy Efficiency and Renewable Energy, Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2007, http://www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/2007_annual_wind_market_report.pdf.

[22] Karen Palmer and Dallas Burtraw, ”Cost-effectiveness of Renewable Energy Policies,” RFF DP 05-01, January 2005, http://www.rff.org/rff/Documents/RFF-DP-05-01.pdf .

[23] “Evidence to the House of Lords Economic Affairs Committee Inquiry into ‘The Economics of Renewable Energy’,” Memorandum by Dr. Phillip Bratby, May 15, 2008, http://www.parliament.uk/parliamentary_committees/lords_economic_affairs/eaffwrevid.cfm.

[24] http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html

[25] http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html

[26] http://www.pewclimate.org/node/1303

[27] Energy Information Administration, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sprdshts.html.

[28] Issues Associated with Renewable Energy in Texas, Informal White Paper for the Texas Legislature, Mar. 28, 2005, page 7, at http://www.ercot.com/news/presentations/2006/RenewablesTransmissi.pdf

[29] Electric Reliability Council of Texas (ERCOT) press release (May 16, 2008), “ERCOT Expects Adequate Power Supplies for Summer,” http://www.ercot.com/news/press_releases/2008/nr-5-16-08 .

[30] Electric Reliability Council of Texas (ERCOT), http://www.ercot.com/meetings/board/keydocs/2008/B0415/Item_6_-_CREZ_Transmission_Report_to_PUC_-_Woodfin_Bojorquez.pdf

[32] California Energy Commission, Intermittency Analysis Project: Summary of Final Results, CEC 500-2007-081 (2007) at 26. http://www.energy.ca.gov/2007publications/CEC-500-2007-081/CEC-500-2007-081.PDF.

[33] http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html

[34] Energy Information Administration, http://www.eia.doe.gov/cneaf/electricity/epa/epa_sprdshts.html

[35] http://www.awea.org/newsroom/releases/wind_energy_growth2008_27Jan09.html

[36] The Lightbucket, The Capacity Factor of Wind, March 13, 2008, http://lightbucket.wordpress.com/2008/03/13/the-capacity-factor-of-wind-power/. Data are tabulated from a number of sources.

[37] http://www.aweo.org/ProblemWithWind.html

[ii] Greenwire, Electricity: “Will Americans learn to love the ‘smart grid’?”, www.eenews.net/Greenwire/2009/02/27/archive/1?terms=smart+grid+cost

[iii] ClimateWire, “Renewable Energy: Pricey ‘supergrid’ seen as key to offshore wind power in Europe”, 2/9/09, www.eenews.net/climatewire/2009/02/09/1

[iv] The Wall Street Journal, “New Grid for Renewable Energy Could Be Costly”, 2/9/09, http://online.wsj.com/article/SB123414242155761829.html

[v] Texas Public Policy Foundation, “Texas Wind Energy: Past, present, and Future”, October 2008, http://www.texaspolicy.com/pdf/2008-09-RR10-WindEnergy-dt-new.pdf

[vi] California Public Utilities Commission, “2007 Resource Adequacy Report”, April 15, 2008, http://docs.cpuc.ca.gov/word_pdf/REPORT/81717.pdf .

[vii] Global Wind Energy Council, http://www.gwec.net/index.php?id=13

[viii] Organization of Economic Cooperation and Development/ International Energy Agency, October 1, 2008, http://www.iea.org/textbase/work/2008/neet_russia/Weis_Taylor.pdf

[ix]Organization of Economic Cooperation and Development/ International Energy Agency, 2008, World Energy Outlook

[x] Global Wind Energy Council, Global Wind 2008 Report, http://www.gwec.net/fileadmin/documents/Global%20Wind%202008%20Report.pdf

[xi] Global Wind Energy Council, Global Wind 2008 Report, http://www.gwec.net/fileadmin/documents/Global%20Wind%202008%20Report.pdf

[xii] The Guardian, March 21, 2009, http://www.guardian.co.uk/environment/2009/mar/21/renewable-energy

[xiii] “Windmills flap helplessly as coal remains king”, February 18, 2009, http://business.timesonline.co.uk/tol/business/industry_sectors/natural_resources/article5 755210.ece

[xiv] Global Wind Energy Council, Global Wind 2008 Report, http://www.gwec.net/fileadmin/documents/Global%20Wind%202008%20Report.pdf

[xv] Study of the effects on employment of public aid to renewable energy sources, Universidad Rey Juan Carlos, March 2009, http://www.juandemariana.org/pdf/090327-employment-public-aid-renewable.pdf .

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Executive Summary

The United Sates is a global leader in coal, both in production and reserves. Environmental issues and a push toward natural gas-fired power plants in recent years have limited new coal-fired generating units, but new coal plant construction is still progressing. The Energy Information Administration and other forecasters predict a robust coal market in the U.S. to meet growing electricity demand and to fuel the emergence of a coal-to-liquids industry.  Surges in U.S. coal exports this year indicate that U.S. coal is important to the global market, as well as to the domestic market, and that other countries, both developed and developing, are investing in coal-fired technology.

U.S. Coal Production and Resource Statistics

• In 2007, coal production totaled 1.15 billion short tons [1].   By 2030, the Energy Information Administration projects coal production to total 1.46 billion short tons, an increase of over 25 percent [2].

• The largest coal producing State is Wyoming with 446.7 million short tons produced in 2006. Over half the states in the U.S. (26 States) produce coal. The coal is transported by truck, train, and barge to consumption areas [3].

• Coal reserves in the U.S. totaled 491 billion short tons as of January 1, 2007, the most in the world.  At current consumption levels, the U.S. has 381 years of coal. See the international section below for other countries with large coal reserves [4].

U.S. Coal Consumption Statistics

• In 2007, coal consumption totaled 1.13 billion short tons, of which 93 percent was used for electricity production, 7 percent in the industrial sector, and 0.3 percent in the residential and commercial sectors [5].   By 2030, the Energy Information Administration projects coal consumption to increase to 1.55 billion short tons, of which 91 percent would be used for electricity generation, 4 percent for coal-to-liquids production, 5 percent in the industrial sector, and 0.3 percent in the residential and commercial sectors [6].   In 2007, coal represented 22 percent of total U.S. supply; in 2030, it is projected to represent 25 percent of the total.

• In 2007, 51 percent of U.S. electricity was generated by coal-fired power plants. EIA predicts that coal-fired generation will supply 54 percent of the electricity in 2030. Generation from coal-fired units is expected to increase by over 800 billion kilowatt hours (42 percent) by 2030– the largest increase of any generating fuel due to its low capital and fuel costs relative to other generating technologies [7].

U.S. Coal Plant Statistics

• The U.S. has 313.6 gigawatts of coal-fired capacity, which is 31 percent of the total generating capacity in the United States.  During the past two decades, little new coal-fired capacity has been added due to the addition of over 250 gigawatts of natural gas-fired combined cycle and turbine units [8].  The EIA projects that 100 gigawatts of new coal-fired power plants will be built by 2030 to meet increased electricity demand, more than any other fuel type capacity [9].

• The Department of Energy’s National Energy Technology Laboratory (NETL) reported that at the end of June 2008, 29 coal-fired plants were under construction (16,534 megawatts), 5 were near construction (1,962 megawatts), 18 were permitted (8,415 megawatts), and 58 were announced (37,438 megawatts) for a total of 64,349 megawatts, all to be on-line within 10 years. A plant near construction has obtained approval and received the majority of its permits, has begun site preparation, and is contracting for vendors and Engineering, Procurement and Construction contractors.  A plant in the permitted phase has two or more permits approved or fuel or power contracts have been negotiated. A plant in the announced phase is in the early stages of development and maybe filing for permits. While plants under and near construction are likely to come on line, NETL warns that regulatory uncertainty and industry cost increases are impacting development decisions for all projects. For example, their year 2002 report of announcements reflected a schedule of over 36,000 megawatts to be installed by 2007, but only 12 percent (about 4,500 megawatts) were actually achieved [10].

• The U.S. has a coal-to-natural gas plant in Beulah, North Dakota.  The Great Plains Gasification Plant converts lignite coal to pipeline quality synthetic natural gas.  The Synfuels plant began operating in 1984 and produces more than 54 billion cubic feet of natural gas annually, consuming over 6 million tons of coal each year [12].

• While there are no coal-to-liquids plants currently in the U.S., the technology exists, was used widely during World War II by Germany, and is currently producing petroleum products from coal in South Africa.  The Energy Information Administration projects that coal-to-liquids production in the U.S. will begin by 2015 and by 2030, it will produce 240,000 barrels per day of petroleum products, consuming 29 million short tons of coal [14].

Emissions

• Combustion of coal produces pollutants such as sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, and carbon monoxide. The Clean Air Act Amendments of 1990 (CAAA) instituted a cap and trade program that requires power plants to meet certain targets for SO2 and NOx emissions.  As a result, emissions of sulfur dioxide from coal-fired electricity generation declined from 15.9 million short tons in 1989 to 9.8 million short tons in 2006, a reduction of 39 percent.  On a per kilowatt basis, SO2 emissions from coal-fired plants declined from .05 tons in 1989 to .03 tons in 2006. NOx emissions from coal-fired generators declined from 8.0 million short tons in 1989, to 3.3 million short tons in 2006, a reduction of 59 percent.  On a per kilowatt basis, NOx emissions from coal-fired power plants declined from .026 tons to .011 tons.  Power plant owners mainly complied with the CAAA by using lower sulfur coal or by adding desulfurization and selective catalytic reduction equipment to their units. Both the lower sulfur coal and the technology to remove SO2 and NOx were available to the power companies when the CAAA became law [15].

• The Environmental Protection Agency’s (EPA) Clean Air Interstate Rule (CAIR) was set up to further limit SO2 emissions in 28 eastern states and the District of Columbia to 3.6 million tons beginning in 2010 and 2.5 million tons in 2015, and NOx emissions to 1.5 million tons in 2009 and 1.3 million tons in 2015 [16].  The U.S. Court of Appeals for the D.C. Circuit on July 11, 2008, issued a decision that struck down CAIR’s emission allowance trading program, holding that unrestricted trading might result in no emission reductions in an upwind state, thereby preventing EPA from fulfilling its responsibility under the Clean Air Act (CAA) to prohibit sources in one state from contributing to nonattainment in another state [17].

• The Clean Air Mercury Rule was set up to limit mercury emissions to 38 tons in 2010 and 15 tons in 2018. To reduce mercury, power companies can change their fuels, change the dispatch or the configuration of their units, or add mercury specific controls, such as selective catalytic reduction equipment or activated carbon injection systems [18].  The Clean Air Mercury Rule was vacated on February 8, 2008, because the court found that mercury is a toxic air pollutant which must be regulated under different provisions of the Clean Air Act, generally requiring the use of the best available control technology (BACT) [19].

• Carbon dioxide emissions in 2007 totaled 5984 million metric tons of CO2, of which coal represented 36 percent. The majority of carbon dioxide emissions from coal (over 90 percent) were emitted from coal-fired electric generators [20].

• U.S. CO2 emissions are expected to total 6,851 million metric tons of CO2 in 2030, of which coal is expected to represent 41 percent, with 92 percent of coal’s share coming from coal-fired electric generators [21].

• Carbon dioxide emissions from coal-fired power plants could be controlled in the future when carbon capture and sequestration (CCS) technology becomes commercially viable. CCS technology captures CO2 emissions at their point of production and injects them in geological formations in the earth. In 2003, the U. S. Government and private industry began funding the FutureGen project to control carbon emissions from coal-fired power plants. The Federal Government withdrew its support early in 2008 for a restructured project where Government funds would be used for the CCS portion of the plant only [22].  Carbon capture and sequestration technology is expected to add about $1 billion to the cost of a new plant and increase power plant efficiency losses [23].

Environmental Issues

• It is becoming harder for new coal plants to get regulatory permits due mainly to their emissions of carbon dioxide. In the United States, of 151 proposals for coal-fired plants in early 2007, more than 60 had been dropped by the year’s end, many blocked by state governments. Dozens of others are stuck in court challenges [24].

• Kansas is an example of a state blocked project to build a coal plant. In October 2007, a state environment official rejected Sunflower Electric Power’s permit to build two 700-megawatt, coal-fired generators on the basis of carbon dioxide emissions — the first such rejection in the U.S.  The state legislature rescinded the decision with bills that would have allowed the plants to proceed. However, Kansas’ Governor, Kathleen Sebelius, vetoed the legislation. And while this Kansas plant is a first, at least 16 other coal plants across the U.S. have been denied for other reasons, including investor uncertainty about future U.S. climate legislation as well as higher construction and labor costs [25].

• Another plant in jeopardy is the proposed Longleaf plant in Georgia , which is tied up in litigation. The plant, proposed by LS Power and Dynegy, would have been the first coal-fired plant built in Georgia in over 20 years, in a state where coal is the primary fuel for electricity generation. In late June, Fulton County Superior Court Judge Thelma Wyatt Cummings Moore overturned the decision by state regulators to issue the plant an air permit, saying state environmental officials failed to take the plant’s carbon dioxide emissions into consideration. In her decision, Moore said the plant would annually emit large amounts of air pollutants, including eight to nine million tons of carbon dioxide [26].

• Some U.S. banks are including “Carbon Principles” in their screening of coal-fired plant investments. Citigroup, J.P. Morgan, Morgan Stanley, and Bank of America expect a federal greenhouse-gas-emissions cap in the next few years that are expected to make conventional coal-fired power plants riskier investments. These “Carbon Principles” push utilities to explore other alternatives to regular coal plants (e.g. natural gas), and urges them to build coal-fired power plants that are carbon capture and sequestration ready, although that technology is not yet commercially available [27].

• Xcel Energy has plans to close two small Colorado coal-fired power plants (combined capacity of 229 megawatts) by 2012 and replace them with a 200 megawatt advanced solar plant. The plan will help Xcel meet Colorado’s renewable portfolio standard calling for 20 percent of the state’s electricity to come from renewable resources by 2020. It will also help Xcel comply with Gov. Bill Ritter’s 2007 mandate to cut utility-sector carbon dioxide emissions by 20 percent below 2005 levels by 2020. By volunteering to shut down the two coal plants, Xcel becomes the first utility in the country to help meet greenhouse gas reduction goals through power plant closures. The company is expected to begin soliciting bids on design and construction of the new solar plant later this year.  Xcel also has plans to build as much as 850 megawatts of wind energy within its service territory by 2015 [28].

• A recently approved coal plant by The Environmental Protection Agency (EPA) is the Desert Rock power plant on the Navajo Nation. The plant will use supercritical coal technology and meet standards defined by the International Energy Agency for carbon capture and storage ready, allowing it to be retrofitted for future deployment of the technology when it becomes commercially available. The 1,500 megawatt plant will be located near Farmington in northwestern New Mexico and will serve parts of Arizona, New Mexico, and Utah.  It will use Navajo Nation coal resources [29].  The plant, however, is being contested by State officials and environmentalists [30].

• Montana’s Crow Nation and Australian-American Energy Company (AECC) announced plans on August 8, 2008, to jointly construct a $7 billion coal-to-liquid (CTL) fuels plant in southeastern Montana. AAEC has completed its initial feasibility study for the project and will begin the environmental permitting process later this year, with construction expected to begin in 2012 and production to begin in 2016. The project is expected to use 38,000 tons of coal per day to produce 50,000 barrels of CTL fuel per day. Ultimately, plant production could be ramped up to reach 125,000 barrels per day. It is designed to capture carbon dioxide for geo-sequestration and supply to enhanced-oil recovery projects [31].

U.S. Coal Exports and Imports

• Coal exports increased by almost 10 million short tons in 2007, reaching 59.2 million short tons, the highest level in 10 years. The U.S. exported 18.4 million short tons to Canada and 27.1 million short tons to Europe in 2007 [32].  The coal export surge continued in 2008, where they jumped almost 51 percent in the first six months versus the same period in 2007. Total coal exports for the first 6 months of 2008 stood at 38.6 million short tons, versus 25.6 million short tons for the first six months of 2007. The export increase can be attributed in part to continuing strong demand in Asia, particularly China and India, as well as a weak U.S. dollar, which makes American coal a better value to overseas buyers [33].

• Coal imports totaled 36.3 million short tons in 2007, about the same level as in 2006 [34].  Colombia dominates the U.S. coal import market, accounting for 73.9 percent of 2007 imports [35].   Coal imports declined 4 percent for the first half of 2008, marking a turnaround from the first six months of 2007, when imports had increased slightly from the previous year [36].

• The EIA and other forecasters, however, project that U.S. coal exports will decline and that the U.S. will become a net importer of coal after 2015. EIA projects that coal exports will decline to 35 million short tons by 2030 and that coal imports will increase to 112 million short tons [37].  However, if coal-fired power plants in the U.S. are blocked by State and local governments for environmental reasons, U.S. coal will most likely be shipped abroad, reversing this forecast, and continuing the trend of the U.S. being a net exporter of coal.

International

• World coal consumption in 2005 was 6,483 million short tons, representing 26 percent of global total primary energy consumption. China consumed 2,333 million short tons and the U.S. consumed about half of China’s consumption at 1,125 million short tons [38].

• World production of coal in 2005 was 6,490 million short tons, with China producing the most at 2,430 million short tons, and U.S. producing 1,132 million short tons [39].

• In 2030, world consumption is expected to increase by 65 percent to 202 quadrillion Btu, with China increasing its consumption by 120 percent to 103 quadrillion Btu. The U.S. is expected to increase its consumption by 31 percent, reaching 30 quadrillion Btu in 2030. Coal is expected to represent 29 percent of total global primary consumption in 2030 [40].

• World recoverable coal reserves as of January 1, 2003, totaled 998 billion short tons.  Recoverable reserves are those quantities of coal which geological and engineering information indicates with reasonable certainty can be extracted in the future under existing economic and operating conditions. Four countries represent 67 percent of the world’s coal reserves: the U.S. (27 percent), Russia (17 percent), China (13 percent), and India (10 percent) [41].

• Worldwide CO2 emissions are expected to be 42 billion metric tons by 2030, up over 50 percent from its 28 billion metric ton level in 2005. Coal represented 41 percent of global CO2 emissions in 2005 and is expected to represent 44 percent in 2030 [42].

• Countries in Europe and Asia are expanding coal capacity despite climate change issues.  China has built as much new coal capacity in each of the past three years as Britain’s total consumption. India has plans to add eight “ultra-mega” plants that will increase its current coal capacity by 50 percent. The Ukraine switched to domestic coal after Russia cut off natural gas supplies in a price dispute two years ago. Germany is planning 16 new coal plants despite carbon emissions trading in Europe [43].

• A small Canadian company is planning to build a coal-to-liquid petroleum fuels plant that will produce 40,000 barrels per day over 50 years starting in 2014. The project is expected to cost C$4.5 billion. Coal reserves in northwestern Alberta will be turned into diesel fuel and naphtha — a heavy oil product used for paving roads and for diluting bitumen from the oil sands— employing proven processes that have been in commercial use around the world for more than 30 years. The venture is expected to break even with oil prices at $50-$60 per barrel and generate returns at $80. The plans include the sale of carbon dioxide into the enhanced oil recovery market. More than 85 percent of CO2 produced by the project will be captured for sequestration in deep saline aquifers or in depleted oil or gas pools [44].

Citations

1. Energy Information Administration (EIA), Annual Energy Review 2007 (AER), Table 7.2, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec7_7.pdf.
2. Energy Information Administration, Annual Energy Outlook 2008 (AEO), Table A15, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
3. Energy Information Administration, State Energy Profiles, http://tonto.eia.doe.gov/state/state_energy_profiles.cfm?sid=WY .
4. Energy Information Administration, Annual Energy Review 2007, Table 4.11, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec4_23.pdf.
5. Energy Information Administration (EIA), Annual Energy Review 2007, Tables 1.3 and 7.3, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec7_9.pdf.
6. Energy Information Administration, Annual Energy Outlook 2008 (AEO), Tables A1 and A15, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html
7. Energy Information Administration (EIA), Annual Energy Review 2007, Table 8.4b, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec8_18.pdf , and EIA, Annual Energy Outlook 2008 (AEO), Tables 6 and A8, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
8. Energy Information Administration (EIA), Annual Energy Review 2007, Table 8.11a, page 260, http://www.eia.doe.gov/emeu/aer/elect.html.
9. Energy Information Administration (EIA), Annual Energy Outlook 2008, Table A9, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
10. National Energy Technology Laboratory, Tracking New Coal-Fired Power Plants, June 30, 2008, http://www.netl.doe.gov/coal/refshelf/ncp.pdf.
11. Energy Information Administration, http://tonto.eia.doe.gov/state/state_energy_profiles.cfm?sid=ND.
12. U.S. Department of Energy, Fossil Energy, http://www.fossil.energy.gov/programs/powersystems/gasification/gasificationpioneer.html .
13. http://www.energyquest.ca.gov/transportation/coal.html.
14. Energy Information Administration, Annual Energy Outlook 2008, Tables A11 and A15, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html .
15. Energy Information Administration, Annual Energy Review 2007, Tables 8.11a and 12.7a, http://www.eia.doe.gov/overview_hd.html.
16. Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, page 86, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf
17. National Mining Association, http://www.nma.org/newsroom/miningweek/miningweekarchive/pdf2008/mw071808.pdf .
18. Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, page 86, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf.
19. National Mining Association,  http://www.nma.org/pdf/misc/021308_camr.pdf .
20. Energy Information Administration, U.S. Carbon Dioxide Emissions from Energy Sources 2007 Flash Estimate, http://www.eia.doe.gov/oiaf/1605/flash/flash.html .
21. Energy Information Administration, Annual Energy Outlook 2008, Table A18, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html
22. http://www.energy.gov/news/5912.htm, http://www.fossil.energy.gov/news/techlines/2008/08030-CO2_Capture_Projects_Selected.html.
23. COAL: Worldwide, dirty fuel not retiring anytime soon, Climate Wire, 08/06/2008, http://www.eenews.net/cw/2008/08/06/7.
24. New York Times, Europe Turns Back to Coal, Raising Climate Fears, April 23, 2008, http://www.nytimes.com/2008/04/23/world/europe/23coal.html?scp=4&sq=coal%20power%20plants&st=cse .
25. Coming in from the Coal, October 19, 2007, http://www.grist.org/news/2007/10/19/Kansas/index.html , and The Washington Post, Gristmill: What’s not the matter with Kansas, July 10, 2008, http://www.washingtonpost.com/wp-yn/content/article/2008/07/15/AR2008071500930.html.
26. Stephanie Cohen, “Coal At A Crossroad,” MarketWatch, August 8, 2008.
27. Wall Street Journal, February 4, 2008, http://blogs.wsj.com/environmentalcapital/2008/02/04/wall-street-tells-big-coal-not-so-fast/?mod=WSJBlog , April 2, 2008, http://blogs.wsj.com/environmentalcapital/2008/04/02/bank-of-america-more-heat-on-coal/ and  August, 13, 2008, http://blogs.wsj.com/environmentalcapital/2008/08/13/burning-cash-coal-friendly-banks-under-fire/
28. E&E News, August 21, 2008, http://www.eenews.net/eenewspm/2008/08/21/2 .
29. New York Times, New Mexico Power Plant Permitted, August 1, 2008, http://www.nytimes.com/2008/08/01/us/01brfs-POWERPLANTPE_BRF.html?_r=1&ref=us&oref=slogin and Desert Energy Project Website, http://www.desertrockenergyproject.com/index.htm.
30. Greenwire, COAL: Extension granted for appeals of N.M. power-plant permit , August 22, 2008, http://www.eenews.net/Greenwire/2008/08/22/8 .
31. National Mining Association, http://www.nma.org/newsroom/miningweek/miningweekarchive/pdf2008/mw081508.pdf
32. Energy Information Administration, Annual Energy Review 2007, Table 7.4, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec7_11.pdf.
33. National Mining Association, http://www.nma.org/newsroom/miningweek/miningweekarchive/pdf2008/mw081508.pdf.
34. Energy Information Administration (EIA), Annual Energy Review 2007, Table 7.1, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec7_5.pdf.
35. Energy Information Administration (EIA), U.S. Coal Supply and Demand, http://www.eia.doe.gov/cneaf/coal/page/special/feature.html.
36. National Mining Association, http://www.nma.org/newsroom/miningweek/miningweekarchive/pdf2008/mw081508.pdf
37. Energy Information Administration, Annual Energy Outlook 2008 (AEO), Tables 13 and A15, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
38. Energy Information Administration, International Energy Annual, http://www.eia.doe.gov/iea/wecbtu.html and http://www.eia.doe.gov/iea/coal.html.
39. Energy Information Administration, International Energy Annual, http://www.eia.doe.gov/iea/coal.html .
40. Energy Information Administration, International Energy Outlook 2008 (IEO), Tables A2 and A7, http://www.eia.doe.gov/oiaf/ieo/ieorefcase.html and http://www.eia.doe.gov/oiaf/ieo/ieorefcase.html .
41. Energy Information Administration, International Energy Outlook 2007, page 50, http://www.eia.doe.gov/oiaf/archive/ieo07/index.html.
42. Energy Information Administration, International Energy Outlook 2008, Table A13, http://www.eia.doe.gov/oiaf/ieo/ieorefcase.html.
43. COAL: Worldwide, dirty fuel not retiring anytime soon, Climate Wire, 08/06/2008, http://www.eenews.net/cw/2008/08/06/7.
44. Turning coal into liquid fuel, Gary Park, Petroleum News, August 3, 2008, www.petroleumnews.com.

U.S. Statistics

• In 2007, nuclear power accounted for 19 percent of the electricity generated and consumed in the United States [1].  This amount of power is comparable to the electricity used in California, Texas, and New York combined [2].  Behind coal, nuclear power and natural gas-fired generation each represent about 20 percent of the electricity generated in the United States [3].

• The United States’ 104 nuclear power plants in 31 states produced 807 billion kilowatt hours of nuclear electricity generation in 2007, more than any other nation in the world [4].

• The Energy Information Administration (EIA) projects that nuclear power generation will increase to 917 billion kilowatt hours by 2030, representing 18 percent of total electricity generation. EIA expects 16.6 gigawatts of new nuclear capacity to be built as a result of incentives in the Energy Policy Act of 2005 (EPACT) [5].  The EPACT subsidy is a production tax credit of 1.8 cents per kilowatt-hour for the first 6,000 megawatts of new nuclear capacity beginning operation by 2020, subject to a $125 million annual limit per gigawatt (1,000 megawatts). The production tax credit applies to the first 8 years of the unit’s operation [6].

• EIA lists 19 potential nuclear projects (29 commercial reactors) in the United States, of which 9 projects have applied for a license to build and operate a plant. The total capacity of all of these potential plants is about 39 gigawatts.  Projects included are those in which the applicant has met all of the following criteria: 1) publicly notified the Nuclear Regulatory Commission (NRC) of interest in applying for a combined license to build and operate new commercial nuclear reactors; 2) issued one or more press releases or initiated a pre-application meeting at the NRC; 3) selected a specific site for the reactor; and 4) selected a specific reactor design for the project. There is no assurance that any of these plants will ultimately be built or operate commercially [7].

• While operating and maintenance costs for nuclear power are less than conventional plants, they have taken longer to build and are more expensive to construct (see below). The average construction-to-operation time for the current fleet of reactors is over 9 years and about 11.5 years if only reactors constructed since 1970 are considered [8].  The Energy Information Administration assumes a new advanced nuclear unit would take six years to build, while new coal- and natural gas-fired plants would take 2 to 4 years, depending on the type of plant [9].

• Accidents at Three Mile Island and Chernobyl turned public opinion against nuclear power. Since then, advances in technology have offered the possibility that future reactors will be made inherently safe from meltdown. While the U.S. nuclear industry has taken steps to reduce the potential for accidents in existing reactors, the public may continue to harbor past fears [10].

Emissions and Nuclear Waste

• Nuclear power plants do not emit carbon dioxide, sulfur dioxide, or nitrogen oxides. Fossil fuel emissions, however, are associated with the uranium mining and uranium enrichment process as well as the transport of the uranium fuel to the nuclear plant [11].  The plants are also concrete-intensive, creating incremental emissions.

• The biggest potential concern with nuclear power relates to the management and disposal of radioactive byproducts. Nuclear power waste is highly toxic and can remain radioactive for anywhere from one to millions of years. While “geologic isolation” offers a long-term disposal solution, the transportation to and from the sites is a major issue. In addition, individuals and communities near nuclear waste storage sites are reluctant to have a nuclear waste dump near their homes [12].

• Yucca Mountain is the nation’s planned geologic repository for spent nuclear fuel, which is currently stored at 126 sites around the nation. Yucca Mountain is located in a remote site on federally protected land within the secure boundaries of the Nevada Test Site in Nye County, Nevada. It is approximately 100 miles northwest of Las Vegas, Nevada. On July 23, 2002, President Bush signed House Joint Resolution 87, allowing the Department of Energy (DOE) to take the next step in establishing a safe repository to store the nation’s nuclear waste. The DOE is currently preparing an application to obtain the Nuclear Regulatory Commission license to proceed with construction of the repository. The Nuclear Waste Policy Act of 1982 requires utilities which generate electricity using nuclear power to pay a fee of one tenth of one cent ($0.001) per kilowatt-hour into the Nuclear Waste Fund, which will be used to pay for Yucca Mountain [13].

What Does A Nuclear Plant Cost?

• EIA assumes the total overnight capital cost of an advanced nuclear plant to be $2,583 per kilowatt (in 2008 dollars) [14].  These costs are below the estimated cost made by the National Association of Manufacturers (NAM) and the American Council for Capital Formation (ACCF) of $3,410 per kilowatt (in 2008 dollars) [15].

• Recent estimates from power companies indicate that the cost could be even higher. Georgia Power Co., a unit of Atlanta-based Southern, said it expects to spend $6.4 billion for a 45.7 percent interest in two new reactors proposed for the Vogtle nuclear plant site near Augusta, Georgia. FPL Group, Juno Beach, Florida, estimates it will cost $6 billion to $9 billion to build each of two reactors at its Turkey Point nuclear site in southeast Florida. Exelon, the nation’s biggest nuclear operator, is considering building two reactors on an undeveloped site in Texas, with a cost between $5 billion and $6.5 billion each [16].

International

• In 2005, world-wide nuclear generation totaled 2626 billion kilowatt hours, with the U.S. generating 30 percent (782 billion kilowatt hours), France generating 16 percent (429 billion kilowatt hours), Germany generating 6 percent (155 billion kilowatt hours), and Russia generating 5 percent (140 billion kilowatt hours) [17].  While France generated only 16 percent of the world’s total nuclear generation in 2005, nuclear power represented 79 percent of the country’s total electricity generation [18].

• In 2005, world-wide nuclear capacity totaled 374 gigawatts, of which the U.S. had 27 percent (100 gigawatts), France had 17 percent (63 gigawatts), Japan had 13 percent (47 gigawatts), Russia had 6 percent (23 gigawatts), and Germany had 5 percent (21 gigawatts) [19].

• International growth in commercial nuclear power has slowed, but several countries have ambitious nuclear construction programs. While no nuclear reactors have been ordered in the United States since 1978, China, India, Russia, and South Korea and other countries have brought new reactors into service during the latter part of the twentieth century [20].

• EIA projects that world nuclear capacity will increase from 374 gigawatts in 2005 to 498 gigawatts in 2030, an increase of 33 percent. China is expected to add 45 gigawatts, India 17 gigawatts, Russia 18 gigawatts, and South Korea 13 gigawatts [21].

• EIA projects that world-wide electricity production from nuclear power will increase by 43 percent by 2030, reaching 3,754 billion kilowatt hours. Increases of over 100 percent are expected to come from China (720 percent), India (831 percent), and Russia (118 percent). However, nuclear power’s share drops from 15% of total world generation in 2005 to 11 percent of total generation in 2030 [22].

Citations

1. Energy Information Administration, Annual Energy Review 2007, Table 8.2a, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec8_8.pdf.
2. Energy Information Administration, Nuclear Basics 101, http://www.eia.doe.gov/basics/nuclear_basics.html.
3. Energy Information Administration, Annual Energy Review 2007, Table 8.2a, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec8_8.pdf.
4. Energy Information Administration, Annual Energy Review 2007, Table s 9.1 and 9.2, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec9_3.pdf , and http://www.eia.doe.gov/cneaf/nuclear/page/nuc_reactors/reactsum.html.
5. EnergyInformation Administration, Annual Energy Outlook 2008, Tables A8 and A9, http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html.
6. Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, page 90, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf.
7. Energy Information Administration, Status of Potential New Commercial Nuclear Reactors in the United States, http://www.eia.doe.gov/cneaf/nuclear/page/nuc_reactors/reactorcom.html.
8. Energy Information Administration, http://www.eia.doe.gov/cneaf/nuclear/page/nuc_reactors/reactsum.html .
9. Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, Table 38, page 79, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf
10. Bradley, Robert, Energy: The Master Resource (Dubuque, IA: Kendall Hunt, 2004), p.27.
11. US Environmental Protection Agency, Electricity from Nuclear Energy, http://www.epa.gov/cleanenergy/nuc.htm.
12. Bradley, Robert, Energy: The Master Resource (Dubuque, IA: Kendall Hunt, 2004), p.27.
13. US Department of Energy, Office of Radioactive Waste Management, http://www.ocrwm.doe.gov/ym_repository/index.shtml.
14. Energy Information Administration, Assumptions to the Annual Energy Outlook 2008, Table 38, page 79, http://www.eia.doe.gov/oiaf/aeo/assumption/index.html.
15. ACCF/NAM Study of the Economic Impact of the Lieberman-Warner Climate Security Act, http://www.accf.org/nam.html.
16. “New Wave of Nuclear Plants Faces High Costs”, Rebecca Smith, Wall Street Journal, May 12, 2008, http://online.wsj.com/article/SB121055252677483933.html.
17. Energy Information Administration, International Energy Annual, Table 2.7, http://www.eia.doe.gov/iea/elec.html.
18. Energy Information Administration, International Energy Annual, Tables 2.7 and 6.3, http://www.eia.doe.gov/iea/elec.html
19. Energy Information Administration, International Energy Annual, Table 6.4, http://www.eia.doe.gov/iea/elec.html.
20. Energy Information Administration, Nuclear Power Generation, http://www.eia.doe.gov/neic/infosheets/nuclear.html.
21. Energy Information Administration, International Energy Outlook 2008, Table H5, http://www.eia.doe.gov/oiaf/ieo/index.html.
22. Energy Information Administration, International Energy Outlook 2008, Table H7 and H11, http://www.eia.doe.gov/oiaf/ieo/index.html.

[1] Ranked in order of 2006 worldwide oil equivalent reserves as reported in "OGJ 200/100", Oil & Gas Journal, September 17, 2007.

[2] Information from Energy Information Administration Country Analysis Briefings .

[3] OPEC member