Energy & Technology
I live in one of those northern and western suburbs of DC that tend to lose power fairly frequently.
It used to be that one of the few nice things about losing power was the sound of silence. But those days are gone. Now losing power has a new sound: the whirring of the startup of my neighbors’ backup generators.
We need power not only to keep our food from spoiling and protect us from uncomfortable and even dangerous heat, but also to stay connected. As a nation, we are becoming ever more dependent on electronic devices. We cannot survive without our cell phones and computers, let alone our refrigerators and air conditioners. At the same time, climate change threatens the reliability of the grid through more intense heat waves and potentially more powerful storms.
While it’s easy to say we should work to prevent disruption in electricity, how much should we invest to bolster the resilience of the grid? And who should pay?
With the latest round of international climate change talks underway in Doha this week, it’s a good time to check in on the United States’ pledge, made three years in Copenhagen, to reduce greenhouse gas emissions 17 percent below 2005 levels by 2020. Are we on track to meet that?
The short answer: Not yet. But projections depend on assumptions, so let’s look at a few recent projections.
I recently got the chance to tag along with a group of journalism fellows on a tour of some oil sands production sites in Alberta, which is home to almost all of Canada’s oil sands reserves.
The Canadian oil sands are one of the biggest energy stories of our time. The good news is that this is a huge North American resource. Because of the oil sands, Canada now has the third largest oil reserves in the world, estimated at 175 billion barrels. The bad news is that extracting this oil can seriously harm the environment. Because of these environmental risks, many oppose the Keystone pipeline, proposed to expand the already significant imports of this oil from Alberta to the United States.
Among Tuesday's election returns, voters in two states issued a split decision on ballot measures to boost clean energy. California approved a plan to fund clean energy jobs, but voters in Michigan defeated a plan to put a stronger clean energy standard for the state’s utilities into the state constitution.
An op-ed this week in The Washington Post, “The Middle America climate strategy,” is correct in saying that we need an energy policy that doesn’t cost more. Unfortunately, Matthew Stepp’s definition of cost, and his prescription for getting to a low-carbon energy supply, are incomplete.
Our current energy policy is imposing enormous costs on our society; it’s just that these costs are hidden from view.
I recently responded to a question on the National Journal blog, "What 's holding back electric cars?"
You can read more on the original blog post and other responses at the National Journal.
Here is my response:
Two out of three respondents in a new University of Texas poll said energy issues are important to them. But the harsh rhetoric of campaign season makes it seem like politicians can never agree on important policies needed to provide safe, reliable and affordable energy while also protecting the environment.
Well they can, and they did. Right now in Washington, D.C., we have a bipartisan bill that would reduce carbon emissions and develop domestic energy resources.
- Solar power accounted for less than 0.2 percent of energy generation in the United States in 2011. Solar power also accounted for 0.5 percent of global electricity demand in 2011.
- Total global solar energy generation capacity averaged 40 percent annual growth from 2000 (1.5 GW) to 2011 (69.8 GW). Solar is the fastest growing source of renewable electricity in the world and in the United States, but it is starting from a small base.
- The average cost per installed watt (system costs including electrical grid connection and other equipment needed for installation) of solar photovoltaics in the United States has dropped from over $7.50/watt in 2009 to $4.44/watt in 2012. In 2011 alone, cost per installed watt declined 17.4 percent.
- Future challenges for solar include grid integration and storage of power for later use, as well as achieving cost reductions for non-panel equipment, financing, and installation
Solar power harnesses the sun’s energy to produce electricity. Solar energy resources are massive and widespread, and they can be harnessed anywhere that receives sunlight. The amount of solar radiation, also known as insolation, reaching the earth’s surface every hour is more than all the energy currently consumed by all human activities annually. A number of factors, including geographic location, time of day, and current weather conditions, all affect the amount of energy that can be harnessed for electricity production or heating purposes (see Figure 1).
Although solar energy is abundantly available, it is also variable and intermittent. Solar power cannot generate electricity at night without storage mechanisms, and is less effective in overcast or cloudy conditions. For this reason, solar power is often used in conjunction with baseload generation from coal, natural gas, nuclear, and hydro sources of power that can provide reserve generation in times of intermittency.
The two main solar technologies for electricity generation are solar photovoltaics (PV), which use semiconductor materials to convert sunlight into electricity, and concentrating solar power (CSP), which concentrates sunlight on a fluid to produce steam and drive a turbine to produce electricity. CSP is a subset of solar thermal energy, which also encompasses water heaters, driers, cookers, and other applications of solar heating.
Figure 1: Average Daily Solar Resource for South-facing PV Panels with Latitude Tilt
|Source: National Renewable Energy Laboratory (NREL), “Photovoltaic Solar Resource of the United States” From Dynamic Maps, GIS data, and Analysis Tools, accessed August 3, 2012. http://www.nrel.gov/gis/solar.html|
Note: This map shows annual average daily total solar resources. The insolation values represent the resource available to a photovoltaic panel oriented and tilted to maximize capture of solar energy. This map displays an annual average; maps for individual months reflect the seasonal variation associated with solar energy.
Solar photovoltaic (PV)
Solar PV is the term used to designate generation that uses the photoelectric effect to produce electricity. Globally, solar PV accounted for 69.8 GW of installed capacity at the end of 2011, and its capacity is expected to increase by about 29.9 GW in 2012. Photovoltaics use semiconductor materials—most frequently silicon but also cadmium telluride and copper indium gallium selenide—to convert sunlight directly into electricity. PV installations can vary substantially in size and are usually divided into three sizes – residential-, commercial-, and utility-scale. The modular nature of solar PV makes it well-suited for distributed generation (small-scale installations close to where the electricity will be used, such as on the roof of a house or business). Concentrated PV, not to be confused with concentrating solar power (defined below), can also be used as utility-scale power plants, known as “solar farms” or “solar plants.”
PV modules are produced by slicing ingots into wafers, most of which are silicon-based. These wafers are then electrically connected and packaged into modules, which can then be assembled into arrays. Today’s silicon-based modules have a conversion efficiency of about 13-20 percent (meaning they convert up to 20 percent of the energy they receive from the sun into electricity) though these efficiencies are improving.
Thin-film technologies use very thin layers (only a few microns) of semiconductor material to make PV cells. Though thin-film PV absorbs more light than silicon wafers, thin-film PV is less efficient at converting light into electricity than traditional PV, and thus needs more surface area to produce a given amount of power. Most thin film efficiencies range between 6 and 11 percent, while silicon-wafer efficiencies are between 15 and 20 percent.
However, thin-film PV cells require significantly less material to manufacture (approximately 5 percent of the material required to make a traditional PV cell). Thin film PV cells are commonly manufactured from lower-grade silicon or non-silicon materials such as CIGS (copper-indium-gallium-diselenide) and CdTe (cadmium telluride), which have lower costs compared to silicon-based PVs. The use of less expensive materials or reductions in the amount of material needed brings down costs for thin-film PVs as opposed to silicon-wafer PV. Moreover, thin-film PV can be integrated into buildings or consumer products, for example, by layering them seamlessly onto roof tiles.
Researchers are developing next-generation materials as well as new methods for producing PVs to increase conversion efficiency and lower production costs. Many of these technologies, for example organic solar cells, are not dependent on rare earth minerals; thin film PV modules, on the other hand, are commonly made from rare earths such as tellurium, gallium, and indium. Concentrating PV, not be confused with Concentrating Solar Power (CSP)–using lenses or mirrors to concentrate sunlight onto special PV materials—may prove to be a lower-cost solar power option. Nano-scale materials, such as carbon nanotubes, could also yield breakthrough applications for PV materials. Others believe they can achieve low-cost solar electricity via the use of organic materials, bioengineering, and streamlined manufacturing processes.
Concentrating solar power (CSP) / Solar Thermal
Globally, CSP accounted for 1.76 GW of installed capacity at the end of 2011. Unlike PV, which converts sunlight directly into electricity, CSP uses the sun’s thermal energy to produce electricity. CSP is mainly a utility-scale application of solar power that uses arrays of mirrors to focus sunlight on a fluid to produce steam to spin an electricity-generating turbine. Because coal and gas-fired power plants also generate steam to spin turbines, solar thermal can potentially be integrated with these plants. CSP systems require a significant amount of area and ideal solar conditions.
CSP, similar to solar PV, has difficulty generating electricity when the sun is not shining. However, working fluids in CSP systems, such as molten salt, give up their heat slowly and can continue to produce steam and therefore electricity for several hours even without direct sunshine. In July 2011, a 19.9 MW CSP plant in Spain became the first utility-scale solar installation to generate electricity for 24 hours straight, using molten salt for energy storage.
CSP technologies include parabolic trough, linear Fresnel reflectors, power towers, and Stirling thermal systems. Parabolic trough, which uses parabolic mirrors to focus light onto a linear pipe, is the most popular CSP technology and accounts for over 90 percent of CSP. Other solar thermal applications outside of electricity generation, known as low-temperature or medium-temperature collectors, include HVAC system designs, solar water heating (e.g., hot water heaters for swimming pools) and cooking. Solar water heating accounted for 172.4 thermal GW in 2009; China accounted for 58.9 percent of this capacity. The U.S. solar water heating industry is growing at 6 percent annually in the United States and has significant potential to expand.
Solar power capacity is expressed as Watt-peak (Wp), which is the amount of power generated by a solar panel at standard testing conditions (STC). Standard testing conditions denote 25 degrees Celsius and an irradiance (or insolation at a specific moment in time) of 1000 watts per meter squared, approximating the sun at noon on a clear day in spring or autumn in the continental United States. For PV, Wp incorporates the absorption efficiency of sunlight into the individual cells as well as the conversion efficiency from solar to electricity. However, because of nighttime, weather conditions, and other issues, the capacity factor of solar PV is around 25 percent, meaning average actual electrical generation over the course of a day is only a quarter of Wp.
Environmental Benefit / Emission Reduction Potential
Electricity produced using solar energy emits no greenhouse gases (GHGs) or other pollutants. As with any electricity-generating resource, the production of the PV systems themselves requires energy that may come from sources that emit GHGs and other pollutants. Since solar PV systems have no emissions once in operation, an average traditional PV system will need to operate for an average of four years to recover the energy and emissions associated with its manufacturing. A thin-film system currently requires three years. Technological improvements are anticipated to bring these timeframes down to one or two years. Thus, a residential PV system that can meet half of average household electricity needs is estimated to avoid 100 tons of carbon dioxide (CO2) over a 30-year lifetime.
It is highly uncertain how quickly and to what extent solar will grow into the future. The IEA envisions a scenario in which nearly one-third of the world’s electricity supply could be from solar by 2060 given improved efficiency and a price on carbon, but all else equal. Carbon dioxide emissions from the world’s energy sector would fall from 30 gigatons in 2011 to 3 gigatons. The European Photovoltaic Industry Association estimates that global cumulative solar PV capacity will be between 208 GW and 343 GW by 2016, corresponding to roughly three to five percent of global electricity demand. This percentage is similar to the current solar share of electricity generation in countries with the most solar generation.
For PV, panel prices are usually denoted as cost per Wp. Costs are also sometimes expressed as cost per installed watt, which includes the price of the DC-AC inverter, connection to the grid, and more. All costs besides the module itself are known as balance-of-system costs. Thus, the addition of balance-of-system costs to the cost of the solar module equals the installed watt costs.
The cost of solar PV has fallen substantially over the last few decades, and especially over the past few years. CSP price declines have also been substantial, but not as sharp as PV price declines. The weighted average cost of PV systems across residential, commercial, and utility-scale installations declined from $10.80 dollars per installed watt in 1998 to just above $7.50 per installed watt in 2007. By Q2 2012, costs have fallen to $4.44 per installed watt. The bulk of these discounts is from diminishing module costs, although the root cause of these diminishing costs is unclear; for individual silicon wafer panels, the average selling price dropped from $1.85/watt to $0.97/watt in 2011 alone, nearly a 50 percent price decline. Diminishing module costs have been driven by a variety of factors including vertical integration, scale efficiencies, overproduction of polysilicon (the key raw material in solar), subsidies, and more., In contrast, when the technology was first developed in the 1950s, solar PV cells cost $300 per watt. Although solar PV prices are forecasted to continue to decline, the magnitude and pace of these price declines are uncertain.
CSP prices have also declined but not kept pace with PV price declines, leading to a shift from planned CSP power plants being converted to PV in 2011, including projects by Tessera Solar, Solar Millenium, and Google/Brightsource. To illustrate this shift, CSP in 2008 accounted for about ten times as much installed capacity as solar PV in the United States; in 2011, solar PV accounted for 1.6 as much capacity as CSP. While a rebound in CSP development may eventually come about, PV continues to remain more cost-effective than CSP while equally satisfying various state mandates such as renewable portfolio standards (RPS). However, compared to PV, CSP offers more developed storage potential as well as integration with conventional turbines normally fueled by fossil fuel combustion.
PV project costs may not decrease as quickly in the U.S. as they have in the past two years, and several market factors could affect the prices of PV modules. Low prices on solar panels in 2011 were in part caused by oversupply from Chinese solar manufacturers, which made up 47.8 percent of global solar cell market share in 2012, but U.S. anti-dumping tariffs of thirty percent may soon be imposed on Chinese solar manufacturers. Moreover, cash grants from the U.S. Department of Treasury, which reimbursed solar developers up to thirty percent of project costs, expired in December 2011 and will affect both PV and CSP project development after 2012. Project developers in the U.S. can now only claim tax credits (Investment Tax Credit) instead of upfront cash grants after 2011, which is a barrier to project development because many solar developers do not have a sufficiently large tax appetite, and developers may need upfront cash to finance the project. The Investment Tax Credit itself, which gives a tax credit for 30 percent of any commercial and residential system, is slated to expire at the end of 2016. Although the magnitude of the effects of these events is uncertain, balance-of-system costs, which now comprise more than half of the installed cost of PV systems (solar modules only comprise 35-40 percent of costs), may present opportunities for further price declines.
Solar generation still remains more expensive than other forms of electricity generation in many areas, but solar power may become comparable or even cheaper than conventional electricity in certain regions in the next few years. A study in late 2011 showed that the levelized cost of a thin film PV system ranges from 10 to 14 cents per kilowatt-hour (kWh) for a utility-scale solar power plant, while home and medium-scale solar installations cost between 12 and 30 cents per kWh. These costs, however, depend on a number of assumptions and are highly sensitive to the inclusion of various tax incentives for solar power, especially the Federal Investment Tax Credit.
Solar prices are forecasted to continue to decline. GTM Research forecasts that the average selling price of silicon modules will fall from about $0.97 per watt to $0.61 per watt by 2015. The U.S. Department of Energy SunShot Initiative aims to reduce PV costs to $1/installed Wp by 2020, which would translate to 6 cents per kWh. These price reductions would allow solar to comprise 14 percent of U.S. electricity consumption by 2030, and 27 percent by 2050. Such shares of generation would lead to 8 percent (181 MMT CO2) and 28 percent (760 MMT CO2) reduction in U.S. CO2 emissions in 2030 and 2050 respectively.
Table 1: Solar Technologies at a Glance (as of early 2012)
Solar PV Price
U.S. Solar PV installed capacity
Global Solar PV installed capacity
CSP (parabolic trough) price
U.S. CSP installed capacity
Global CSP installed capacity
Obstacles to Further Development and Deployment of Solar Power
Electricity generated from solar power remains more expensive than other forms of electricity in many places. Moreover, in recent years, the supply of rare earth minerals commonly used for PV manufacturing has become constrained. China supplies 97 percent of the world’s rare earth minerals and has enacted production and export quotas, driving higher the price of rare earth minerals. The uncertain future of the supply of rare earths is a risk to the U.S. PV manufacturing industry, but efforts are underway to develop a domestic supply of rare earth minerals as well as the use of solar technologies that do not use supply-constrained materials. For the time being, rare earth supply has met the growth of solar in demand, and has not been a limiting factor in the price declines of solar power.
Solar power, especially solar PV, is constrained by intermittency issues because of weather factors and the fact that daylight hours are limited. CSP storage technologies are being developed to alleviate intermittency problems, although integrated storage remains costly. Solar power is also constrained by the uneven geographic distribution of solar resources, which ultimately encumbers integration with the larger electric grid. To achieve its full potential, solar power will rely on a variety of advanced enabling technologies such as demand response and improvements in energy storage. Energy storage technologies would allow electricity generated during peak production hours (i.e., on bright, sunny days) to be stored for use during periods of lower or no generation. The National Renewable Energy Laboratory (NREL) has published a series of studies examining whether intermittent renewable including solar are capable of providing up to 80 percent of electricity demand.
Solar power, specifically utility-scale PV and CSP, is also held back by a lack of transmission infrastructure (necessary to access solar resources in remote areas, such as deserts, and transport the electricity to end users). These areas often have the highest potential for solar generation.
However, solar technologies offer a number of opportunities for “on-site” or “distributed generation” applications in which energy is produced at the point of consumption, including rooftop PV arrays and building-integrated photovoltaic (BIPV) systems. Such systems, known as local PV, can make solar power more cost competitive by avoiding costs associated with transmission and distribution. However, technical problems in regulating the local grid must be solved before local PV reaches its full potential.
Policy Options to Help Promote Solar Power
Price on carbon
A price on carbon, (e.g. under a carbon tax or GHG cap-and-trade program) would raise the cost of coal and natural gas generation, making solar more cost competitive in more parts of the country, especially as technological advancements continue to bring down the cost of solar power.
Renewable portfolio standards
A renewable portfolio standard (or an alternative energy portfolio standard) requires that a certain percentage or absolute amount of a utility’s power plant capacity or generation or sales come from renewable or alternative sources by a given date. As of July 2012, 31 U.S. states and the District of Columbia had adopted a mandatory RPS or AEPS and an additional seven states had set renewable energy goals. Renewable portfolio standards encourage investment in new renewable generation and can guarantee a market for this generation. States and jurisdictions can further encourage investment in specific resources, such as solar power, by including a carve-out or set-aside in an RPS, as is the case in the District of Columbia and 12 states (all of which mandate that a given percentage of their renewable energy requirements be met through new solar generation).
Development of new transmission infrastructure
Policies that promote the buildout of new electricity transmission lines (such as the streamlining of transmission siting procedures) allow access to these resources, thereby providing additional incentives for utilities to invest in them. Lack of transmission can also be addressed by instead incentivizing distributed electricity generation using solar PV, rather than focusing on large, utility-scale systems.
Feed-in tariffs and other financial incentives
Feed-in tariffs (FiTs)promote the deployment of solar power or other renewable electricity generation by guaranteeing electricity generators a fixed price for electricity produced from particular resources (e.g. solar), usually enough above the retail price for electricity to cover the costs of the generation and also provide the generator a profit. Typically, utilities are required to purchase this electricity at the specified price and then spread the additional costs across the utility bills of its customers. This fixed price is usually guaranteed for some specified period of time. (Germany, one of the most high-profile examples of a country employing feed-in tariffs, guarantees the fixed rate for 20 years.) These policies might also direct electrical grid operators to give priority to electricity produced from solar power or other renewables. Federal financial incentives include the Investment Tax Credit, which is valid until 2016, and the payment in lieu of tax credits (PILOT), which expired in 2011.
Other financial incentives to promote solar power can include tax incentives or credits, net metering, and loan programs. These incentives can be offered to utilities or to individual customers installing their own power systems.
Growth in solar power has relied heavily on policy and financial incentives, but price declines may make solar development profitable on its own. Europe had more than 51 GW of installed capacity in 2011, primarily because of FiTs and other incentives. In comparison, the United States only had 4.4 GW and China had 3.1 GW. Solar power in both countries is forecasted to grow quickly.
Related C2ES Resources
- Wind and Solar Electricity: Challenges and Opportunities, 2009.
- Race to the Top: The Expanding Role of U.S. State Renewable Portfolio Standards, 2006.
- Net Metering State Map, 2012.
- Renewable & Alternative Energy Portfolio Standard Map, 2012.
- Clean Energy Standards: State and Federal Policy Options and Implications, 2011,
- Clean Energy Markets Jobs and Opportunities, 2011.
Further Reading / Additional Resources
U.S. Department of Energy, Sunshot Vision Study, 2012 http://www1.eere.energy.gov/solar/pdfs/47927.pdf
International Energy Agency (IEA): Solar Heating and Cooling Programme, Solar Heat Worldwide: Markets and Contribution to the Energy Supply 2009, 2011 http://www.iea-shc.org/statistics/SolarHeatWorldwide/index.html
International Renewable Energy Agency (IRENA), Renewable Energy Technologies: Cost Analysis Series Volume 1: Power Sector, Issue 2/5 Concentrating Solar Power, 2012 http://www.irena.org/DocumentDownloads/Publications/RE_Technologies_Cost_Analysis-CSP.pdf
Solar Energy Industries Association (SEIA) and Greentech Media Research, U.S. Solar Market Insight Report: 2011 Year-in-Review, 2012 http://www.slideshare.net/SEIA/us-solar-market-insight-report
European Photovoltaic Industry Association (EPIA), Global Market Outlook for Photovoltaics Until 2016, 2012 http://files.epia.org/files/Global-Market-Outlook-2016.pdf
International Energy Agency (IEA), Energy Technology Perspectives 2012: Scenarios and Strategies to 2050, 2010 http://www.iea.org/etp/
U.S. Department of Energy (DOE)
- Tracking the Sun: The Installed Cost of Photovoltaics in the U.S. from 1998-2009, by R. Wiser, G. Barbose, and C. Peterman, 2010 http://eetd.lbl.gov/ea/ems/reports/lbnl-4121e.pdf.
- National Renewable Energy Laboratory. Solar PV Manufacturing Cost Model Group: Installed Solar PV System Prices. February 2011. http://arpa-e.energy.gov/LinkClick.aspx?fileticket=2WF9d-ukumA%3D&tabid=408
- Energy Efficiency & Renewable Energy. U.S. State Clean Energy Data Book. October 2010. http://www.nrel.gov/docs/fy11osti/48212.pdf
U.S. Energy Information Administration. Annual Energy Outlook, Renewables. http://www.eia.gov/forecasts/aeo/data.cfm?filter=renewable#renewable
International Energy Agency. Technology Roadmap: Solar Photovoltaic Energy. 2010 http://www.oecd-ilibrary.org/energy/technology-roadmap-solar-photovoltaic-energy_9789264088047-en;jsessionid=7tgn15975dltb.delta
International Energy Agency. Technology Roadmap: Concentrating Solar Power. 2010 http://www.oecd-ilibrary.org/energy/technology-roadmap-concentrating-solar-power_9789264088139-en;jsessionid=7tgn15975dltb.delta
International Energy Agency Solar Power and Chemical Energy Systems (SolarPACE). http://www.solarpaces.org/Library/AnnualReports/annualreports.htm
 Massachusetts Institute of Technology Energy Initiative. The Future of the Electric Grid Chapter 3: Integration of Variable Energy Resources. Cambridge, MA: MIT, 2011. http://web.mit.edu/mitei/research/studies/documents/electric-grid-2011/Electric_Grid_3_Integration_of_Variable_Energy_Resources.pdf
 EIA. Table 1.3 Primary Energy Consumption by Source. May 2012. http://www.eia.gov/totalenergy/data/monthly/pdf/sec1_7.pdf.
 European Photovoltaic Industry Association (EPIA). Global Market Outlook for Photovoltaics Until 2016. May 2012. http://files.epia.org/files/Global-Market-Outlook-2016.pdf
 International Energy Agency (IEA). Renewable Energy Division. Technology Roadmap Solar Photovoltaic Energy. Paris:OECD/IEA, 2010. Web 01 Mar. 2012. http://www.oecd-ilibrary.org/energy/technology-roadmap-solar-photovoltaic-energy_9789264088047-en;jsessionid=7tgn15975dltb.delta
 Quantum Solar Power. “A Comparison of PV Technologies.” Accessed July 19, 2012.
 U.S. Department of Energy (U.S. DOE). Critical Materials Strategy. December 2010. http://energy.gov/sites/prod/files/edg/news/documents/criticalmaterialsstrategy.pdf
 Chandler, D. “All-carbon solar cell harnesses infrared light..” MITnews, 2010. Accessed 21 Jun 2012. http://web.mit.edu/newsoffice/2012/infrared-photovoltaic-0621.html
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 Torresol Energy. Gemasolar plant description. Accessed August 2012. http://www.torresolenergy.com/TORRESOL/gemasolar-plant/en
 Sawin, L. and E. Martinot. “Renewables Bounced Back in 2010, Finds Ren21 Global Report.” Renewable Energy World Magazine. 29 Septmember 2011. http://www.renewableenergyworld.com/rea/news/article/2011/09/renewables-bounced-back-in-2010-finds-ren21-global-report
 Weiss, W. and F. Mauthner. Solar Heat Worldwide: Markets and Contribution to the Energy Supply 2009, Edition 2011. Gleisdorf, Austria: AEE Institute for Sustainable Technologies, May 2011. http://www.iea-shc.org/statistics/SolarHeatWorldwide/index.html
 Trabish, H. K. “Solar Hot Water at Intersolar: Something Old, Something New, Something Borrowed.” Greentech Media, 11 July 2012. Accessed August 2012. http://www.greentechmedia.com/articles/read/solar-hot-water-at-intersolar-something-old-something-new-something-borrowe/
 IMTSolar. “Standard Test Conditions (STC) in the Photovoltaic (PV) Industry.” Accessed August 2012. http://www.imtsolar.com/public/files/IMT%20Solar_STC%20for%20PV%20APP%20NOTE.pdf
 EPIA, 2012.
 Barbose, G., N. Darghouth, R. Wiser, and J. Steel. Tracking the Sun IV: A Historical Summary of the Installed Costs of Photovoltaics in the United States from 1998 to 2010. Lawrence Berkeley National Laboratory, Report No. LNL-5047e, 2011. http://eetd.lbl.gov/ea/ems/reports/lbnl-5047e.pdf
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 Shepherd, William. Energy Studies. London: Imperial College Press, 2003.
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 U.S. Energy Information Administration (EIA). Annual Energy Outlook 2011. Table 120. Accessed August 2011. http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=0-AEO2011&table=67-AEO2011®ion=3-0&cases=ref2011-d020911a
 Mufson, S. “China’s growing share of the solar market comes at a price.” The Washington Post, 16 December 2011. Accessed August 2012. http://www.washingtonpost.com/business/economy/chinas-growing-share-of-solar-market-comes-at-a-price/2011/11/21/gIQAhPRWyO_story.html
 SEIA, January 2012.
 Branker, K., M. Pathak, and J. Pearce. “A Review of Solar Photovoltaic Levelized Cost of Electricity” Renewable & Sustainable Energy Reviews, 2011: pp. 4470-4482. http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2006631
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 Stanway, D. and R. Lian. “China Minmetals calls for rare earth production suspension”. Reuters: 3 August 2011. Accessed August 2011. http://www.reuters.com/assets/print?aid=USTRE77219A20110803
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 EPIA, 2012.
On September 30, California Governor Jerry Brown signed two bills into law, establishing guidelines on how an expected $1 billion-plus of annual revenue from the state’s cap-and–trade program will be disbursed. The two laws do not identify specific projects that will benefit from the revenue, but they provide a framework for how the state will invest cap-and-trade program revenue into local projects. California’s first quarterly cap-and-trade GHG allowance auction is set for November 14, 2012. At least 21,804,529 greenhouse gas (GHG) allowances, in this first auction, each representing one ton of carbon dioxide, will be auctioned off to over 600 approved industrial facilities and utilities.
The first law, AB 1532, requires that the revenue from allowance auctions be spent for environmental purposes, with an emphasis on improving air quality. The second, SB 535, requires that at least 25 percent of the revenue be spent on programs that benefit disadvantaged communities, which tend to suffer to a disproportionate extent from air pollution. The California Environmental Protection Agency will identify disadvantaged communities for investment opportunities, while the Department of Finance will develop a 3-year investment plan and oversee the expenditures of this revenue to mitigate direct health impacts of climate change.
These two new laws follow final regulations, adopted by the California Air Resources Board (ARB) on October 20, 2011 for a cap-and-trade program that will help the state reduce greenhouse gas emissions to 1990 levels by the year 2020. The development of California’s cap-and-trade system is authorized by the California Global Warming Solutions Act (AB 32), which was signed into law by Governor Schwarzenegger in 2006.
Beginning in 2013, cap-and-trade regulations will apply to all major industrial sources and electric utilities, and will expand in 2015 to cover the distributors of transportation fuels, natural gas, and other fuels. The amount of allowances available to these sources is set to decline by about 3 percent each year as the cap is lowered and emissions are reduced.
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- Enhanced geothermal systems utilize advanced, often experimental, drilling and fluid injection techniques to augment and expand the availability of geothermal resources, which can be used to generate electricity from the heat in the earth’s crust.
- Enhanced geothermal systems, when recharged, can provide near continuous output, making the technology a renewable, zero-carbon option for supplying baseload electricity generation.
- While no commercial-scale enhanced geothermal plants exist today, a panel of geothermal experts convened by MIT in 2006 estimated that, with the proper incentives, enhanced geothermal systems could provide 100,000 megawatts (MW) of generating capacity by 2050, equivalent to 10 percent of today’s generating capacity.
The term enhanced geothermal systems (EGS), also known as engineered geothermal systems (formerly hot dry rock geothermal), refers to a variety of engineering techniques used to artificially create hydrothermal resources (underground steam and hot water) that can be used to generate electricity. Traditional geothermal plants (see Climate TechBook: Geothermal Energy) exploit naturally occurring hydrothermal reservoirs and are limited by the size and location of such natural reservoirs. EGS reduces these constraints by allowing for the creation of hydrothermal reservoirs in deep, hot geological formations, where energy production had not been economical due to a lack of fluid or permeability. EGS techniques can also extend the lifespan of naturally occurring hydrothermal resources.
Given the costs and limited full-scale system research to date, EGS remains in its infancy, with only research and pilot projects existing around the world and no commercial-scale EGS plants to date. The technology is promising, however, as a number of studies have found that EGS could quickly become widespread. One MIT study projected that EGS could reach an installed capacity of 100,000 MW in the United States by 2050—for comparison the United States currently has roughly 319,000 MW of coal-fueled generating net summer capacity. Were the United States to realize a significant fraction of this potential, it would make EGS one of the most important renewable energy technologies.
According to the U.S. Geologic Survey, the western United States has sufficient geological resources for over 517,800 MW of EGS capacity—roughly the equivalent of half the current total U.S. installed electric generating capacity from all energy sources. Nonetheless, the technologies needed to utilize this energy reserve are not yet commercially viable. According to the MIT report, realizing the theoretical potential of EGS will require consistent investment in research and development for up to 15 years before commercial viability and deployment are achieved. 
Figure 1: EGS resources at depth of 10km
Similar to traditional geothermal generation, EGS technologies use the heat of the earth’s crust to generate electricity. Traditional geothermal plants draw on naturally occurring hydrothermal resources at relatively shallow depths. EGS, however, attempts to artificially reproduce the conditions of naturally occurring hydrothermal reservoirs by fracturing impervious hot rocks at 3 to 10 kilometers depth, pumping fluid into the newly porous system, and then extracting the heated fluid to drive an electricity-generating turbine (see Figure 2). Artificially creating hydrothermal reservoirs gives EGS greater siting flexibility than traditional geothermal power plants, which can only be developed at sites with naturally occurring hydrothermal resources that may be limited in their size and their proximity to end-users of electricity.
The backbone and most difficult elements of EGS are the creation of the hydrothermal reservoir and a flow of fluid—typically water--through the fractured rock. In order to operate continuously, a geothermal plant must have access to a steady stream of heated fluid. This requires the creation of a reservoir that not only holds enough fluid but also allows it to readily move through the system. However, the hot rocks best suited for EGS are rarely porous enough, as they are buried so deep that they become compressed by the weight of the earth. As a result, EGS begins with increasing the natural porosity of a geological structure—often referred to as “stimulation.” Upon drilling an initial bore hole, highly pressurized water is pumped underground. As pressure mounts, the water stimulates fractures that branch out through the geological formation, creating a hydrothermal reservoir. Stimulation can be assisted by treatments involving the injection of various acids into the reservoir to corrode accumulated debris. 
After stimulation, EGS operators must estimate the volume and shape of the newly created reservoir. A variety of technologies, from seismic imaging to radioactive tracers, can then be used to design the best array of injection and production wells. In proposed designs, the injection well will be placed near the center of the reservoir, with multiple production wells flanking either edge of the reservoir. This allows water to flow outward from the injection well in all directions, optimizing flow rate and minimizing fluid loss. Once the reservoir has been established, it is functionally similar (with exceptions for well cost, restimulation and fluid replenishment) to traditional hydrothermal systems. An EGS power plant operates almost exactly like a traditional geothermal plant. Water is injected into the man-made hydrothermal reservoir, heated as it percolates through the stimulated fractures, and finally extracted at a production well, where it travels to the surface to drive an electricity-generating turbine. It is projected that the majority of EGS plants will use binary cycle geothermal technology to convert hydrothermal resources to electricity.
Figure 2: EGS Cutaway Diagram
Source: U.S. Department of Energy Geothermal Technologies Program. 2008. An Evaluation of Enhanced Geothermal Systems Technology.
The widespread application of EGS, however, will ultimately depend on advances in drilling technology. While oil and gas drilling techniques apply to geothermal drilling (both traditional and EGS), temperatures above 250°F that are necessary for geothermal reservoirs complicate the process. The high heat increases the probability of well failure due to collapse, mechanical malfunction, loss of telemetry, and casing failure.,, These limitations apply doubly to EGS wells, as EGS drilling requires drilling deeper, into harder and hotter rock than traditional geothermal plants.
Environmental Benefit / Emission Reduction Potential
EGS, like traditional geothermal energy, constitutes a source of electricity that is almost entirely free of greenhouse gas (GHG) emissions. Only small traces of carbon dioxide and other GHGs might be released from geological formations during the drilling phase of an EGS plant’s life. 
The greatest environmental benefit of EGS comes from its ability to satisfy baseload electricity demand. Unlike intermittent renewable energy technologies, such as wind and solar power, EGS could provide a consistent electricity supply similar to carbon-intensive coal-fired power plants. Replacing the generation from a typical 500 MW coal-fired power plant with electricity from geothermal plants would avoid about 3 million metric tons of CO2 emissions per year (roughly 0.1 percent of total U.S. CO2 emissions from electricity generation).
The installation of EGS would likely be expanded under a national climate or energy policy. Unfortunately, projections of renewable energy innovation under climate policies typically do not include predictions about EGS growth, given the experimental nature of the technology.
These same projections, however, expect traditional geothermal to grow under a climate policy. The overlap of the two geothermal technologies means that innovations in traditional geothermal should bolster the prospects of EGS as well. According to a panel of experts convened by MIT in 2006, EGS could reach an installed capacity of 100,000 MW by 2050—roughly a third of today’s installed coal capacity.
Abandoned or unproductive domestic oil fields could be adapted to EGS. The unproductive oil fields of Texas, for example, not only have already drilled bore holes, but also have verified thermal and geological information. Retooling these fields to produce hot water, instead of oil, could greatly expand the installed capacity of EGS once it reaches commercial deployment.
The experimental nature of EGS technology makes it difficult to evaluate the costs of a commercial scale EGS power plant. Initial estimates suggest that with current technology, the capital costs of an EGS plant would be roughly twice that of a traditional geothermal plant. While the capital costs of an EGS plant currently exceed those of a traditional fossil fuel power plant, one must look at the actual cost of generating electricity. Unlike a coal or natural gas plant, EGS facilities do not need to purchase fuel to generate electricity. This difference can be accounted for through a levelized cost analysis. Estimates of the cost of EGS vary and are uncertain because the cost of reservoir creation varies greatly depending on the geological formations at each EGS site. Using current drilling technology at an ideal site (marked by high temperatures at shallow depths and easily drillable geology), would allow for electricity generation at an estimated levelized cost of 17.5 to 29.5 cents per kilowatt-hour (kWh). At less suitable, yet still technically feasible locations (that require deeper drilling, often through hard granite formations), EGS could generate electricity at a cost of as much as 74.7 cents per kWh.
EGS costs are especially difficult to calculate given that current EGS plants are small pilot facilities designed for research, not power production. Subsequent commercial-scale plants are expected to achieve economies of scale. As such, the costs of currently operating plants provide limited insight into the costs of a commercial-scale EGS facility. Cost reductions seen for similar technologies used in the oil and gas industry in the past indicate the potential for significant cost reductions for EGS. With time, as EGS nears commercialization, EGS is projected to competitively produce electricity at 3.6 to 9.2 cents per kWh.,
The variability in cost estimates is largely attributable to the risks and inherent variability involved in the drilling and reservoir development stages of EGS. Drilling alone is estimated to be more than one-third of the capital costs of an EGS plant. EGS drilling is especially expensive given the greater depths often required to reach geological formations of sufficient heat. Deeper bore holes require more materials and have higher risks of failure, causing drilling costs to increase nonlinearly with depth. At a depth of 6,000 meters, drilling the initial bore hole for EGS is projected to cost $12 million to $20 million—roughly two to five times greater than oil and gas wells of comparable depth. Furthermore, these estimates do not include the cost of exploratory well drilling, a necessary but expensive step in developing a geothermal site that entails both risk and uncertainty.
Current Status of Enhanced Geothermal Energy
EGS remains in the research and development stage. Experimentation with EGS first began in the 1970s with a series of pilot projects at Fenton Hill, New Mexico. While the projects did not operate on a commercial scale, they did demonstrate the feasibility of the geologic engineering and drilling techniques needed to artificially create hydrothermal reservoirs. Since then, experimental EGS plants and pilot projects have been undertaken around the world. Realizing the full potential of EGS will take some time, and the International Energy Agency (IEA) believes that substantially higher research, development, and demonstration (RD&D) efforts are needed to ensure EGS becomes commercially viable by 2030.
In the United States, there has been growing interest in EGS. In 2009, the American Recovery and Reinvestment Act included $80 million for research and development of EGS technologies. The U.S. Department of Energy’s (DOE) Geothermal Technologies Program oversees on-going research and development related to EGS with the goal of improving the performance and lowering the cost of EGS technologies. The Geothermal Technologies Program partners with national laboratories, universities, and the private sector on EGS component technology research and development projects and EGS system demonstration projects. Two prominent EGS-related research projects are wastewater injection at The Geysers in California (the oldest geothermal field in the United States and largest geothermal venture in the world) and Desert Peak in Nevada, where EGS capacity will be added to an existing geothermal field. Finally, the Bureau of Land Management leases land in eleven Western states for continued geothermal resource development.
The European Union has long been involved in the efforts to research and develop enhanced geothermal systems technologies. France and Germany have operational EGS demonstration projects (1.5 to 2.5 MW), while Iceland and Switzerland are members of the International Partnership for Geothermal Technology (IPGT). The United States and Australia are also members of the IPGT, which is working to identify effective methodologies and practices for EGS development.
Obstacles to Further Development or Deployment of EGS
Need for Technology Research, Development, and Demonstration (RD&D)
A lack of RD&D constrains the deployment of EGS power plants. Most technologies used in EGS, such as drilling and geologic imagery techniques, are not yet adapted for specific use in EGS development.
High-Risk Exploration Phase
The exploratory phases of a geothermal project are marked by not only high capital costs but also a 75 percent chance of failure, when high fluid temperatures and flow rates are not located . The combination of high risk and high capital costs can make financing geothermal projects difficult and expensive.
Knowledge of Geothermal Geology
The ability to artificially create geothermal reservoirs consistently is greatly limited due to a lack of understanding of how geothermal reservoirs occur in nature. Researching the geological characteristics of natural geothermal resources is essential to adapting stimulation and drilling techniques in such a way that drives down the costs of EGS development.
Geographic Distribution and Transmission
Despite the siting flexibility of EGS technologies, the most promising EGS sites often occur great distances from regions of large electricity consumption, or load centers. The need to install adequate transmission capacity can deter investment in geothermal projects.
Policy Options to Help Promote EGS
Price on Carbon
A price on carbon would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from renewable sources, such as EGS, and other lower-carbon technologies. A price on carbon would increase both deployment of mature low-carbon technologies and R&D investments in less mature technologies.
Clean Energy Standard
A clean energy standard is a policy that requires electric utilities to provide a certain percentage of electricity from designated low carbon dioxide-emitting sources. At present, 31 U.S. states and the District of Columbia have adopted clean energy standards, and clean energy standard has been proposed at the federal level. Clean energy standards encourage investment in new renewable generation and can guarantee a market for this generation.
Research, Development and Demonstration
Rapidly moving along the EGS technological “learning curve” requires sustained funding of further research efforts in the form of pilot plants and basic research in geology, drilling techniques and other associated EGS technologies.
Streamline Government Leasing and Permitting Procedures
Quickly deploying EGS will require federal agencies to more efficiently process applications for the development of EGS plants on public lands. Accelerating the speed of siting, leasing and permitting decisions will help make already risky EGS projects more attractive to investors.
Development of New Transmission Infrastructure
Improving transmission corridors to areas with geothermal reservoirs would facilitate investment in geothermal energy. Policies to build new transmission to areas with significant renewable energy resources are already proposed for accessing the wind-rich regions of the central plains and the extensive solar resources of the desert Southwest. Such policies could also promote expanded transmission to reach the geothermal fields of the West.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
U.S. Department of Energy (DOE). 2008. The Basics of Enhanced Geothermal Systems.
DOE’s Geothermal Technologies Program website
Geothermal Energy Association. 2012. “Geothermal Basics.”
International Energy Agency (IEA). 2011. Technology Roadmap - Geothermal Heat and Power
International Partnership for Geothermal Technology’s website
 “Tester, J., et al. 2006. The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century. Massachusetts Institute of Technology.
 U.S. Department of Energy. 2008. “The Basics of Enhanced Geothermal Systems.” Accessed 22 August 2012. http://www1.eere.energy.gov/geothermal/pdfs/egs_basics.pdf
 Williams, E., et al. 2007. A Convenient Guide to Climate Change Policy and Technology. http://www.nicholas.duke.edu/ccpp/convenientguide/cg_pdfs/ClimateBook.pdf
 U.S. Energy Information Administration (EIA). 2011. “Table 8.11a Electric Net Summer Capacity: Total (All Sectors), 1949-2010.” Accessed 2 May 2012.
 Williams, C., et al. 2008. Assessment of Moderate-and High-Temperature Geothermal Resources of the United States. United States Geological Survey. http://pubs.usgs.gov/fs/2008/3082/pdf/fs2008-3082.pdf
 Tester et al., 2006.
 For an illustrated explanation, see the U.S. Department of Energy’s Geothermal Technologies Program’s webpage: “How an Enhanced Geothermal System Works” http://www1.eere.energy.gov/geothermal/egs_animation.html
 U.S. Department of Energy (DOE). 2008a. An Evaluation of Enhanced Geothermal Systems Technology. http://www1.eere.energy.gov/geothermal/pdfs/evaluation_egs_tech_2008.pdf
 DOE, 2008a.
 Tester et al., 2006.
 Rather than using hydrothermal steam to drive a turbine, a binary cycle geothermal plant uses heated water from the hydrothermal reservoir to vaporize a “working fluid,” any fluid with a lower boiling point than water (e.g., iso-butane). The vaporized working fluid drives a generator while the geothermal water is promptly reinjected into the reservoir, without ever leaving its closed loop system. To learn more about the conversion of hydrothermal resources to electricity see C2ES Climate TechBook: Geothermal Energy, 2009.
 DOE. 2008c. Multi-year Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025. http://www1.eere.energy.gov/geothermal/pdfs/gtp_myrdd_2009-complete.pdf
 DOE, 2008a.
 A well’s casing is the pipe placed in a wellbore as an interface between the wellbore and the surrounding formation. It typically extends from the top of the well and is cemented in place to maintain the diameter of the wellbore and provide stability. Telemetry refers to the transmission of data from the drill bit to the operators on the surface.
 Fridleifsson, I.B., et al. 2008. The possible role and contribution of geothermal energy to the mitigation of climate change. In: O. Hohmeyer and T. Trittin (Eds.) IPCC Scoping Meeting on Renewable Energy Sources, Proceedings, Luebeck, Germany, 20-25 January 2008, 59-80.
 Kagel, A., Bates, D. and Gawell, K. 2007. A Guide to Geothermal Energy and the Environment. Yet these emissions should not be considered a disadvantage to geothermal energy. In fact, the gases released through geothermal energy production would have eventually entered the atmosphere, regardless of production in the area. In other words, the production of geothermal energy essentially generates zero net GHG emissions. (See Williams, E., et al. 2007). http://geo-energy.org/reports/environmental%20guide.pdf
 U.S. Environmental Protection Agency (EPA). 2011. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009.
 Assuming a coal-plant capacity factor of 70 percent and an emissions rate of 1 metric ton CO2 per MWh.
 For example, the U.S. Energy Information Administration (EIA) models proposed climate and energy policies but does not include EGS as a technology choice in its model, stating that EGS are not included as potential resources since this technology is still in development and is not expected to be in significant commercial use within the projection horizon [by 2030].” See EIA, Assumptions to the Annual Energy Outlook 2009: Renewable Fuels Module. http://www.eia.gov/oiaf/aeo/assumption/pdf/0554(2009).pdf
 EIA, 2011.
 This practice involves creating hydrothermal reservoirs within the geological structures of abandoned oil fields. This allows the EGS plant operators to take advantage of verified thermal and geological data in order to more cheaply create a hydrothermal reservoir. For more information, see McKenna, J., et al. “Geothermal electric power supply possible from Gulf Coast, Midcontinent oil field waters.” The Oil and Gas Journal. 103:33 (2005).
 McKenna et al., 2005.
 Delaquil, P., Goldstein, G., and Wright, E. 2008. “US Technology Choices, Costs and opportunities under the Lieberman-Warner Climate Security Act: Assessing Compliance Pathways.” International Resources Group. http://docs.nrdc.org/globalwarming/files/glo_08051401A.pdf
 The levelized cost of electricity is an economic assessment of the cost of electricity generation from a representative generating unit of a particular technology type (e.g. wind, coal, EGS) that includes costs over the lifetime of the plant: initial investment, operations and maintenance, cost of fuel, and cost of capital. The levelized cost generally does not include costs associated with transmission and distribution of electricity. Levelized cost estimates can vary based on uncertainty regarding and differences in underlying assumptions, such as the size and application of the system, what taxes and subsidies are included, location of the system, and other factors.
 Tester et al., 2006.
 DOE, 2008b.
 Western Governors’ Association. 2006. Geothermal Task Force Report. Clear and Diversified Energy Initiative.
 Tester et al., 2006.
 Deloitte. 2008. Geothermal Risk Mitigation Strategies Report. Prepared for Department of Energy, Office of Energy Efficiency and Renewable Energy Geothermal Program. http://www1.eere.energy.gov/geothermal/pdfs/geothermal_risk_mitigation.pdf
 International Energy Agency (IEA). 2011. Geothermal Heat and Power Roadmap. http://www.iea.org/papers/2011/Geothermal_Foldout.pdf
 DOE. 2009. “Recovery Act Announcement: President Obama Announces Over $467 Million in Recovery Act Funding for Geothermal and Solar Energy Projects.” http://apps1.eere.energy.gov/news/progress_alerts.cfm/pa_id=173
 DOE. 2012. “Geothermal Technologies Program - EGS Component R&D.” http://www4.eere.energy.gov/geothermal/projects?filter[field_project_area]=%2248%22
 DOE 2012. “Geothermal Technologies Program - EGS Systems Demonstration.” http://www4.eere.energy.gov/geothermal/projects?filter[field_project_area]=%2249%22
 Bureau of Land Management (BLM). 2011. “Renewable Energy and the BLM: GEOTHERMAL.” http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS__REALTY__AND_RESOURCE_PROTECTION_/energy.Par.74240.File.dat/Fact_Sheet_Geothermal_Oct_2011.pdf
 Ledru, P. et al. 2007. “ENhanced Geothermal Innovative Network for Europe: the state-of-the-art.” Geothermal Resources Council Bulletin. http://engine.brgm.fr/Documents/GRC_ENGINE_Presentation_06092006.pdf
 GEA, 2012.
 IGPT, 2012.
 DOE, 2008b.
 Deloitte, 2008.
For an example of this work, see Blankenship, D., et al. 2009. Development of a High-Temperature Diagnostics-While-Drilling Tool. Sandia Report 2009-0248. http://www1.eere.energy.gov/geothermal/pdfs/ht_dwd_tools.pdf
 See footnote 9 in Tester et al., 2006.
 Center for Climate and Energy Solutions (C2ES). 2012a. “C2ES State Policy Map - Renewable & Alternative Energy Portfolio Standards.” Accessed 22 August 2012. http://www.c2es.org/what_s_being_done/in_the_states/rps.cfm
 C2ES. 2012b. Summary of the Clean Energy Standard Act. http://www.c2es.org/docUploads/bingaman-clean-energy-standard-act-summary.pdf.