Energy & Technology

Keystone XL Pipeline

Keystone XL Pipeline

What is Keystone?

Where does the Keystone XL proposal stand?

Why does TransCanada want to build Keystone XL?

How much does the U.S. rely on oil from Canada?

What are the Canadian oil sands?

What are the greenhouse gas implications of developing the oil sands?

What other environmental concerns does Keystone XL raise?

What are the long-term solutions?

TransCanada’s proposed Keystone XL pipeline has emerged as a symbolic flashpoint in the complex debate over energy, the environment, and the economy.  Pipeline advocates argue that the project will create tens of thousands of jobs and – by increasing the flow of Canadian oil into the United States – will lower gasoline prices and strengthen energy security.  Pipeline opponents counter that any such benefits will be minimal and far outweighed by the project’s environmental consequences, including an increase in climate-warming greenhouse gas emissions. 

While each argument has some merit, the reality is less black-and-white than either suggests: 

  • If rising demand for oil continues to drive development of the Canadian oil sands, the oil is likely to reach global markets with or without Keystone.
  • Increased imports from Canada would reduce U.S. reliance on oil from more volatile regions such as the Mideast.  But because oil is a global commodity, prices are largely a function of global supply and demand, and the U.S. would still be vulnerable to price shocks as a result of geopolitical instability and other factors affecting global oil price.
  • Most of the greenhouse gas emissions come from the tailpipes of vehicles powered by gasoline produced from the oil sands.  But because the process of extracting oil from the oil sands is so energy-intensive, its total carbon footprint is larger than that of most “conventional” oil.  More can and should be done to reduce the carbon emissions generated on the production side.  But in terms of impact on the climate, the overall level of oil consumption is far more critical than the relative carbon profiles of different supplies.

Whether or not Keystone is built is likely to have only marginal implications for the price of gasoline or the pace of global warming.  The most effective response to both challenges is to reduce demand for oil and over time end our reliance on it. 

Here is a more detailed look at the issues behind the Keystone debate:

Figure 1. North America Pipelines

Source: Theodora. 2008.
Key: Crude oil pipelines (Green), Natural gas pipelines (Red), and Refined petroleum products (Blue).

Figure 2. Keystone Expansion Map

Source: TransCanada (2011)

What is Keystone? An extensive network of pipelines carries crude oil, natural gas and refined petroleum products across North America (Figure 1).  One piece of that network is the 2,150-mile Keystone pipeline system operated by TransCanada (solid orange line in Figure 2), which has the capacity to deliver 730,000 barrels per day (b/d) of Canadian crude oil from Hardisty, Alberta to Wood River and Patoka, Illinois; Steele City, Nebraska; and Cushing, Oklahoma.

Keystone XL (dashed line in Figure 2) is a proposed expansion of the existing Keystone system, and is one of a number of projects being proposed to transport greater volumes of Canadian oil sands crude to world market. It would transport Canadian oil sands crude to the U.S. Gulf Coast for refining or export. The planned expansion consists of a northern and southern segment:

  • The approximately 1,200-mile northern segment would travel from Hardisty, Alberta to Steele City, Nebraska via the Canadian Provinces of Alberta and Saskatchewan, and the U.S. states of Montana, South Dakota and Nebraska.
  • The 532-mile southern segment, referred to as the Gulf Coast Pipeline and Houston Lateral Project (or Cushing Marketlink or Southern Keystone) would run from Cushing, OK to Port Arthur, TX and Houston, TX.

Keystone is not the only oil pipeline from the Canadian oil sands. The Alberta Clipper, a 1,000 mile crude oil pipeline operated by Enbridge between Hardisty, Alberta and Superior, WI, went into service in 2010 with an initial capacity of 450,000 b/d and will have an ultimate capacity of up to 800,000 b/d.
(Back to Top)

Where does the Keystone XL proposal stand? On March 1, 2013, the U.S. State Department issued a draft Supplemental Environmental Impact Statement (SEIS) on the project.  After a 45-day comment period, the final SEIS will be issued and will likely be subject to at least a 30-day comment period. The State Department’s National Interest Determination period will be based on the final SEIS and views of other departments and agencies. A final decision granting or denying the Presidential Permit would come no earlier than mid- to late July.

In November 2011, the U.S. State Department delayed a decision regarding the Canadian oil sands pipeline pending further environmental review, effectively putting it off until after the 2012 election. The delay stemmed from the State of Nebraska's decision to seek an alternative route for the pipeline that would avoid the environmentally sensitive Nebraska Sand Hills. Congress then enacted legislation forcing a quicker decision. In January 2012, citing inadequate time to assess the pipeline’s environmental impact, President Obama denied the permit, but left the door open for an alternative route for the contentious northern portion of the pipeline.

TransCanada submitted a new application proposing alternative routes for the northern portion in April 2012, aiming for an in-service date of 2015. On January 22, 2013, Nebraska Governor Dave Heineman submitted a letter to the Department of State announcing his approval of the route reviewed in the Final Evaluation Report of the Keystone Nebraska Reroute by the Nebraska Department of Environmental Quality (NDEQ).

President Obama has supported the southern portion of the pipeline, and on July 27, 2012, TransCanada received the last of three permits needed from the U.S. Army Corps of Engineers to begin construction. Construction began in August 2012 with an anticipated in-service date of mid-to-late 2013. The project will have the initial capacity to transport 700,000 b/d to the Gulf Coast, and can be expanded to transport 830,000 b/d when the full Keystone system is in place.
(Back to Top)

Why does TransCanada want to build Keystone XL? The impetus for this pipeline’s construction is to transport a greater volume of Canadian oil sands crude to world markets. Currently, infrastructure for transporting this crude to international ports is inadequate. Increased supply, both  from the Canadian oil sands and U.S. oil production in North Dakota (Bakken formation), is currently bottlenecked in Cushing, OK. Additional pipeline capacity, including the reversal of the Seaway pipeline [1] and the construction of the southern portion of Keystone, is likely to reduce this bottleneck. Oil sands producers are also attempting to secure permits to build the Northern Gateway and TransMountain pipelines, which would provide an outlet to world markets via the coast of British Columbia. Furthermore in August 2013, TransCanada announced its intention to construct the Energy East pipeline to deliver 1.1 million barrels per day of oil sands crude to refineries and ports in Eastern Canada (Quebec and New Brunswick). At the same time, crude shipments by rail are underway and expected to transport more than 500,000 barrels per day by the end of 2014.

The long-term supply impact of adding Keystone XL to the North American crude oil transport system depends on a number of factors, including global supply and demand over time and whether other pipelines are built to carry Canadian oil sands out of Alberta. In the short run, a rise in deliveries of heavy Canadian oil sands crude to U.S. Gulf Coast refineries is likely to fill a supply gap being created by declining imports from traditional heavy crude suppliers, notably Mexico and Venezuela; a gap that would otherwise be filled by increases from other foreign suppliers, notably from the Middle East. Therefore, it is likely in the near-term that Canadian oil sands would be refined and consumed in the United States. In the long term, with changing market conditions, Keystone XL could help facilitate exports of crude or refined product from the Gulf Coast.
(Back to Top)

How much does the U.S. rely on oil from Canada?  Canada is the largest supplier of U.S. oil imports. In 2011, Canada, Mexico and Saudi Arabia were the top three suppliers of U.S. oil imports. Canada supplied nearly 24 percent of U.S. oil imports, while Mexico and Saudi Arabia each accounted for around 10.5 percent. In 2010, Alberta oil sands supplied 15 percent of U.S. oil imports. In 2011, total oil supplied by Persian Gulf countries (Saudi Arabia, Kuwait and Iraq) averaged 1.8 million b/d, compared to total Canadian imports of 2.7 million b/d.

Total U.S. oil imports peaked in 2005 and 2006 at an average of around 13.7 million b/d. In 2011, U.S. oil imports averaged around 11.36 million b/d.  The decline was due in part to a sluggish economic recovery and increasing domestic supply. Imports from OPEC countries are down around 19 percent over the same period (2005 to 2011), and total imports from Canada have increased by 24 percent.

The Energy Information Agency (EIA) predicts that U.S. oil consumption will grow very slowly over the next 25 years, because of policies that that boost the fuel efficiency of cars and increase the use of renewable fuels like ethanol.
(Back to Top)

What are the Canadian oil sands? Canada has one of the largest proven oil reserves in the world. About 97% of Canadian oil reserves are contained in Albertan oil sands.

Oil sands are a mix of naturally occurring bitumen, sticky oil and abrasive sand; each sand grain is coated by a layer of water and a layer of heavy oil. [2]  According to the Alberta Energy and Utilities Board, (2007) oil sands deposits total 173 billion barrels of proven reserves.  About 26 billion barrels are under active development.[3] Technologies for oil sands production are steadily improving, decreasing greenhouse gas intensity and cost of extraction while increasing the volume of recoverable reserves.

Table 1. Top 20 Countries’ Crude Oil Reserves (Billion Barrels)


Saudi Arabia*
























United Arab Emirates*
























United States
































World Total



*OPEC Country
Source: U.S. Energy Information Administration, International Energy Statistics

Currently, about half of the oil sands production is from surfacing mining, and half is extracted in place, or in-situ.  Ultimately, about 80 percent of the proven oil sands reserves are expected to be produced in-situ. Surface-mined oil sands production is similar to traditional mineral mining; shovel-excavated sands are transported to processing facilities by very large trucks. Crushed sand fragments are added to swirling water (continuously recycled), and the slurry is agitated and piped to an extraction facility, where the oil can be skimmed from the top of the flow.

Figure 3. Surface Mining and In-Situ Production

Source:Nexen Incorporated 2012.

Surface mining is used for shallower reservoirs – those less than 75 meters below the surface; however, 80 percent of the oil sand reserves are deeper and not economically recoverable with surface mining; they require in-situ extraction. There are two main in-situ extraction techniques referred to as steam assisted gravity drainage (SAGD) and cyclic steam stimulation, in which steam, solvents and/or hot air is injected directly into the oil sands in order to get the material to flow into collection pipes. For both processes, extracted bitumen is then upgraded into a lighter (lower viscosity) and sweeter (lower sulfur content) crude oil and later refined into gasoline or diesel fuels.

The Great Canadian Oil Sands (GCOS) project began operations in 1967, with rapid growth occurring over the 1990 – 2006 period. Oil sands production is projected to grow from 1.5 million b/d in 2010 to 3.7 million b/d in 2021. Overall, total Canadian oil production is expected to grow from 2.8 million b/d in 2010 to 4.7 million b/d in 2025.


Figure 4. Canadian Oil Sands and Conventional Production

Source: Canadian Association of Petroleum Producers (2011)

The U.S. Midwest is currently the primary export market for western Canadian crude oil supplies due to its geographic proximity and established pipeline infrastructure. Growing supplies of crude oil from western Canada could find a market on the U.S. Gulf Coast or world markets once they reach Canada’s West Coast, including California and Asia.
(Back to Top)

What are the greenhouse gas implications of developing the oil sands?  The draft SEIS issued by the State Department in March 2013 concluded that the Albertan oil sands will continue to be developed whether or not the Keystone pipeline is built and, therefore, that allowing the pipeline would not lead to a net increase in global greenhouse gas emissions. However, the International Energy Agency in its World Energy Outlook 2013 concluded that current expansion plans for the oil sands are contingent on the development of major new pipelines.

The production of oil sands crude is more energy-intensive, and therefore more greenhouse gas-intensive, than most conventional crudes. Due to the nature of the deposit, additional processes are required to extract the oil, remove the sand and get the oil to flow in a pipeline. Each of these processes, including the use of power shovels and trucks, operation of intermediate facilities, and so forth, requires energy.  In addition, in-situ production (because it requires steam generation) is more energy-intensive than surface mining.

Several analyses of the well-to-wheels life-cycle emissions of transportation fuels produced from various crudes (emissions from both the production and the combustion of the oil) conclude that Canadian oil sands are among the most carbon-intensive. The State Department’s draft SEIS found that oil from the Canadian oil sands is 17 percent more carbon-intensive than the average oil consumed in the United States.  (A report from the Congressional Research Service put the figure at 14 percent to 20 percent.) It is estimated that the U.S. greenhouse gas footprint would increase by 3 million to 21 million metric tons per year, or around 0.04 percent to 0.3 percent of the 2010 levels, if Keystone is built.

This relatively small increase in projected U.S. emissions reflects the fact that the majority of greenhouse gas emissions associated with oil result from its combustion in vehicles.  Well-to-pump emissions, also known as non-combustion emissions, account for 20 to 30 percent of total life-cycle emissions, while fuel combustion accounts for 70 to 80 percent of total life-cycle emissions (Figure 5).  Combustion emissions do not vary with the origin of the crude oil.  Although oil sands-derived crudes are more energy-intensive than the average oil consumed in the United States, there are several types of crudes that are also higher than the U.S. average. Other carbon-intensive crude oils are produced, imported, or refined in the United States, including Venezuelan heavy, California heavy, and Nigerian.

Figure 5. Life-Cycle Greenhouse Gas Emissions

Source: IHS CERA, “Oil Sands, Greenhouse Gases, and U.S. Oil Supply.” (2010)

While the emissions intensity of oil sands are higher than the U.S. average, steps are being taken to mitigate their greenhouse gas intensity. According to the U.S. State Department, oil sands mining projects have reduced greenhouse gas emissions intensity by an average of 29 percent between 1990 and 2008. Additionally, carbon dioxide emissions from oil sands production can be lowered through technological processes such as VAPEX.  VAPEX captures carbon emissions from power plants and industrial sources as an injectant for in-situ production while simultaneously sequestering carbon. In 2008, the Alberta government announced a $2 billion fund to support a combination of sequestration projects in power plants and oil sands extraction and upgrading facilities. Two large projects have received funding: Alberta Carbon Trunk Line and Shell Quest. These projects are expected to reduce Alberta’s greenhouse gas emissions by 2.8 million tonnes annually (15.8 million tonnes at full capacity) beginning in 2015.

In the future, the difference in carbon intensity between the Canadian oil sands and other crudes is expected to narrow.  Emissions from surface-mining oil sands are expected to remain relatively stable over time, while advances in in-situ production are expected to lower its emissions.  At the same time, tertiary recovery of other crudes is expected to become more energy-intensive.
(Back to Top)

What other environmental concerns does Keystone XL raise?  Additional environmental concerns arise from the siting of the pipeline in the United States and at the source of the oil sands production in Canada.

The proposed path of the northern branch of the Keystone XL would cross the Ogallala Aquifer.  This aquifer is a significant source of drinking and irrigation water from South Dakota to Texas. Some groups are concerned that a potential oil spill could result in the fouling of this water source.

In Canada, there are a host of environmental issues, ranging from land disturbance, leveling of the Boreal forest, air pollution, water usage and fouling, interference with migratory animals, and the altering of ecosystems.

Figure 6. Surface Mine and a Tailings (Waste Water) Pond in Fort McMurray, Alberta

Source:Center for Climate and Energy Solutions 2009.
(Back to Top)

What are the long-term solutions? Solutions are available to address issues associated with oil demand, oil sands production, and Keystone XL pipeline construction. Operators have a responsibility to ensure the highest levels of pipeline safety. Ongoing investments and improvements in maintenance and monitoring are imperative, and systems should be in place to minimize accidents over the life of these long-term assets.

Additional steps should be taken to reduce the greenhouse gas emissions that are the direct result of Canadian oil sands production. Techniques like VAPEX and carbon capture and storage, as well as advancements in reducing the energy intensity of in-situ mining, should be promoted and encouraged.

In the long term, the most effective way to reduce the greenhouse gas emissions associated with the oil sands is to dramatically reduce our oil consumption. This can be achieved through technological advances, including development of alternative transportation technologies like plug-in electric vehicles (PEVs) and crude oil substitutions like lower-emitting biofuels for transportation and industry consumers. Crude oil demand can be further reduced through policy initiatives, including increased fuel efficiency Corporate Average Fuel Economy standards, renewable fuel standards, and internalizing the external cost by adding a carbon price to crude oil, such as a carbon tax.  The current fuel economy standard for a manufacturer’s light duty fleet is 27.3 mpg. This will increase to approximately 50 mpg by 2025. Our 2011 report titled Reducing Greenhouse Emissions from U.S. Transportation identifies cost-effective solutions that will significantly reduce transportation's impact on our climate.
(Back to Top)

[1] The Seaway pipeline is a 50/50 joint venture between Enterprise Products Partners, the operator, and Enbridge. It runs from Cushing, OK to Freeport, TX, just to the south of Houston.  It was initially intended to deliver crude from south to north, but work to complete its reversal was completed in May 2012.  Its initial capacity is 150,000 b/d, and this is expected to reach 400,000 b/d by early 2013.  This is expected to relieve the glut of oil in Cushing.

[2] Energy Resources Conservation Board, “Oil Sands.”

[3] Energy Resources Conservation Board ST98–2011 Alberta's Energy Reserves 2010 and Supply/Demand Outlook 2011–2020 (ERCB, 2011). 


Not yet on track to 17 percent reduction

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.

Oil sands up close

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.

Mixed results for clean energy in state elections

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.

A “Middle America” climate strategy must include policies to bring clean energy to market

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.

Patience and policy needed on drive toward sustainability

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:

An energy solution with true bipartisan support

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

Quick Facts

  • 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.[1] 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.[2]

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.

Solar power accounted for less than 0.2 percent of energy generation in the United States in 2011.[3]  Solar power also accounted for 0.5 percent of global electricity demand in 2011.[4]

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.

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.[5] 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.”

Wafer photovoltaics

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.[6]

Thin-film photovoltaics

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.[7]

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.[8] 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.

Next-generation photovoltaics

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.[9] 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.[10] Others believe they can achieve low-cost solar electricity via the use of organic materials, bioengineering, and streamlined manufacturing processes.[11]

Concentrating solar power (CSP) / Solar Thermal

Globally, CSP accounted for 1.76 GW of installed capacity at the end of 2011.[12] 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.[13]

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.[14] 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.[15] The U.S. solar water heating industry is growing at 6 percent annually in the United States and has significant potential to expand.[16]

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.[17] 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.[18]

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.[19] 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.[20]


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.[21] By Q2 2012, costs have fallen to $4.44 per installed watt.[22] 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.[23] 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.[24],[25] In contrast, when the technology was first developed in the 1950s, solar PV cells cost $300 per watt.[26] 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.[27] 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.[28] 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,[29] 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.[30] 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.[31] 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.[32] 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.[33] 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.[34]

Table 1: Solar Technologies at a Glance (as of early 2012)



Solar PV Price

$4.44/installed watt[35]

U.S. Solar PV installed capacity

4.4 GW[36]

Global Solar PV installed capacity

69 GW[37]

CSP (parabolic trough) price

$5.79/installed watt[38]

U.S. CSP installed capacity

0.507 GW[39]

Global CSP installed capacity

1.76 GW[40]

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,[41] 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,[42] 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.[43] 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.[44]


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.[45]

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Further Reading / Additional Resources

U.S. Department of Energy, Sunshot Vision Study, 2012

International Energy Agency (IEA): Solar Heating and Cooling Programme, Solar Heat Worldwide: Markets and Contribution to the Energy Supply 2009, 2011

International Renewable Energy Agency (IRENA), Renewable Energy Technologies: Cost Analysis Series Volume 1: Power Sector, Issue 2/5 Concentrating Solar Power, 2012

Solar Energy Industries Association (SEIA) and Greentech Media Research, U.S. Solar Market Insight Report: 2011 Year-in-Review, 2012

European Photovoltaic Industry Association (EPIA), Global Market Outlook for Photovoltaics Until 2016, 2012

International Energy Agency (IEA), Energy Technology Perspectives 2012: Scenarios and Strategies to 2050, 2010

U.S. Department of Energy (DOE)

U.S. Energy Information Administration. Annual Energy Outlook, Renewables.

International Energy Agency. Technology Roadmap: Solar Photovoltaic Energy. 2010;

International Energy Agency. Technology Roadmap: Concentrating Solar Power. 2010;

International Energy Agency Solar Power and Chemical Energy Systems (SolarPACE).

[1] Lewis, S. and D. Nocera. “Powering the Planet: Chemical Challenges in Solar Energy Utilization.” August 2006.

[2] Massachusetts Institute of Technology Energy Initiative. The Future of the Electric Grid Chapter 3: Integration of Variable Energy Resources. Cambridge, MA: MIT, 2011.

[3] EIA. Table 1.3 Primary Energy Consumption by Source. May 2012.

[4] European Photovoltaic Industry Association (EPIA). Global Market Outlook for Photovoltaics Until 2016. May 2012.

[5] Ibid.

[6] International Energy Agency (IEA). Renewable Energy Division. Technology Roadmap Solar Photovoltaic Energy. Paris:OECD/IEA, 2010. Web 01 Mar. 2012.;

[7] Quantum Solar Power. “A Comparison of PV Technologies.” Accessed July 19, 2012.

[8] Ibid.

[9] U.S. Department of Energy (U.S. DOE). Critical Materials Strategy. December 2010.

[10] Chandler, D. “All-carbon solar cell harnesses infrared light..” MITnews, 2010. Accessed 21 Jun 2012.

[11] IEA, 2010.

[12] Reve (Revista Eolica y del Vehiculo Electrico).”Global capacity of concentrated solar power rose to 1,760 MW.” 19 June 2012.

[13] Torresol Energy. Gemasolar plant description. Accessed August 2012.

[14] Sawin, L. and E. Martinot. “Renewables Bounced Back in 2010, Finds Ren21 Global Report.” Renewable Energy World Magazine. 29 Septmember 2011.

[15] 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.

[16] Trabish, H. K. “Solar Hot Water at Intersolar: Something Old, Something New, Something Borrowed.” Greentech Media, 11 July 2012. Accessed August 2012.

[17] IMTSolar. “Standard Test Conditions (STC) in the Photovoltaic (PV) Industry.” Accessed August 2012.

[18] U.S. Department of Energy National Renewable Energy Laboratory (NREL). “PV FAQs.” December 2004.

[19] International Energy Agency. “Topic: Solar (PV and CSP).” Accessed August 2012.

[20] EPIA, 2012.

[21] 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.

[22] U.S. Solar Energy Industry Association (SEIA) and GTM Research. U.S. Solar Market Insight: Q2 2012. SEIA, July 2012

[23] U.S. Solar Energy Industry Association (SEIA) and GTM Research. U.S. Solar Market Insight: 2011 Year-in-Review. SEIA, January 2012

[24] Barbose, et al., 2011.

[25] Panzica, B. “Solar Pricing’s Rapid Decline.” Energy & Capital, 26 September 2011. Accessed August 2012.

[26] Shepherd, William. Energy Studies. London: Imperial College Press, 2003.

[27] Barber, D.A. “Are PVs Pricing-out CSP Projects in the U.S.?” EnergyTrend TrendForce, 8 September 2011. Accessed August 2012.

[28] U.S. Energy Information Administration (EIA). Annual Energy Outlook 2011. Table 120. Accessed August 2011.

[29] Mufson, S. “China’s growing share of the solar market comes at a price.” The Washington Post, 16 December 2011. Accessed August 2012.

[30] SEIA, January 2012.

[31] Branker, K., M. Pathak, and J. Pearce. “A Review of Solar Photovoltaic Levelized Cost of Electricity” Renewable & Sustainable Energy Reviews, 2011: pp. 4470-4482.

[32] Greentech Media Staff. “When will the pain subside? GTM Forecasts 21GW of PV Module Capacity to Retire by 2015.” Greentech Media, 5 July 2012. Accessed August 3012.

[33] U.S. DOE. SunShot Initiative Website: About. U.S. DOE. Accessed August 11, 2011.

[34] U.S. Department of Energy. Sunshot Vision Study. U.S. DOE: 2012.

[35] SEIA, July 2012

[36] Ibid.

[37] Ibid.

[38] International Renewable Energy Agency (IRENA). Renewable Energy Technologies Cost Analysis Series: Concentrating Solar Power. IRENA: June 2012.

[39] U.S. Energy Information Administration (EIA). Annual Energy Outlook 2012. Table 120. Accessed August 2012.

[40] U.S. Energy Information Administration (EIA). Annual Energy Outlook 2012. Table 120. Accessed August 2012.

[41] Stanway, D. and R. Lian. “China Minmetals calls for rare earth production suspension”. Reuters: 3 August 2011. Accessed August 2011.

[42] Finley, B. “China’s control of rare-earth metals poses risk to U.S. solar future.” Denver Post. January 16, 2011. Accessed August 2011.

[43] Scott, J. “Rare Earth Prices Double in Two Weeks as China Seeks to Increase Control.” Bloomberg: 17 June 2011. Accessed August 2011.

[44] NREL. Renewable Electricity Futures Study (RE Futures). NREL, 2010. Accessed August 2012.

[45] EPIA, 2012.



California passes guidelines for $1 billion of cap-and-trade revenue

Promoted in Energy Efficiency section: 


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. 


For more information:

C2ES: California Cap-and-Trade Program Summary Table

C2ES: California Global Warming Solutions Act

California Air Resources Board: Auction Notice

California Air Resources Board: Press release for cap and trade auction

Press release: Speaker John A. Pérez's AB 1532 Greenhouse Gas Reduction Bill

Enhanced Geothermal Systems

Quick Facts

  • 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.[1]


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.[2] EGS techniques can also extend the lifespan of naturally occurring hydrothermal resources.[3]

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.[4] 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.[5] 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. [6]

Figure 1: EGS resources at depth of 10km

Source: 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.


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,[7] pumping fluid into the newly porous system, and then extracting the heated fluid to drive an electricity-generating turbine (see Figure 2).[8] 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.[9] 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.[10] 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.[11] Stimulation can be assisted by treatments involving the injection of various acids into the reservoir to corrode accumulated debris. [12]

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.[13] 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.[14]

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.[15],[16],[17] These limitations apply doubly to EGS wells, as EGS drilling requires drilling deeper, into harder and hotter rock than traditional geothermal plants.[18]

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. [19]

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[20]).[21]

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.[22]

These same projections, however, expect traditional geothermal to grow under a climate policy.[23] 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.[24]

Abandoned or unproductive domestic oil fields could be adapted to EGS.[25] 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.[26]


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.[27] 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.[28] 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).[29] 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.[30]

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.[31] 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.[32],[33]

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.[34] 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.[35] 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.[36] 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.[37]

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.[38] 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.[39]

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.[40] 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[41] and EGS system demonstration projects.[42] 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.[43] Finally, the Bureau of Land Management leases land in eleven Western states for continued geothermal resource development.[44]

The European Union has long been involved in the efforts to research and develop enhanced geothermal systems technologies.[45] France and Germany have operational EGS demonstration projects (1.5 to 2.5 MW),[46] while Iceland and Switzerland are members of the International Partnership for Geothermal Technology (IPGT).[47] The United States and Australia are also members of the IPGT, which is working to identify effective methodologies and practices for EGS development.[48]

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 .[49] The combination of high risk and high capital costs can make financing geothermal projects difficult and expensive.[50]

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.[51]

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.[52]

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,[53] and clean energy standard has been proposed at the federal level.[54] 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


DTE Energy


Johnson Controls


Related C2ES Resources

Climate Change 101: Technological Solutions, 2011

Race to the Top: The Expanding Role of U.S. State Renewable Portfolio Standards, 2006

C2ES Climate TechBook: Geothermal Energy, 2011

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.”

Tester, Jefferson, 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.

International Energy Agency (IEA). 2011. Technology Roadmap - Geothermal Heat and Power

International Partnership for Geothermal Technology’s website



[1] “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.

[2] U.S. Department of Energy. 2008. “The Basics of Enhanced Geothermal Systems.” Accessed 22 August 2012.

[3] Williams, E., et al. 2007. A Convenient Guide to Climate Change Policy and Technology.

[4] U.S. Energy Information Administration (EIA). 2011. “Table 8.11a  Electric Net Summer Capacity:  Total (All Sectors), 1949-2010.” Accessed 2 May 2012.

[5] Williams, C., et al. 2008. Assessment of Moderate-and High-Temperature Geothermal Resources of the United States. United States Geological Survey.

[6] Tester et al., 2006.

[7] Ibid.

[8] For an illustrated explanation, see the U.S. Department of Energy’s Geothermal Technologies Program’s webpage:  “How an Enhanced Geothermal System Works

[9] U.S. Department of Energy (DOE). 2008a. An Evaluation of Enhanced Geothermal Systems Technology.

[10] DOE. 2008b. Geothermal Tomorrow 2008.

[11] DOE, 2008a.

[12] Ibid.

[13] Tester et al., 2006.

[14] 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.

[15] DOE. 2008c. Multi-year Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025.

[16] DOE, 2008a.

[17] 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.

[18] 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.

[19] 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).

[20] U.S. Environmental Protection Agency (EPA). 2011. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009.

[21] Assuming a coal-plant capacity factor of 70 percent and an emissions rate of 1 metric ton CO2 per MWh.

[22] 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.

[23] Ibid.

[24] EIA, 2011.  

[25] 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).

[26] McKenna et al., 2005.

[27] 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.

[28] 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.

[29] Tester et al., 2006.

[30] Ibid.

[31] Ibid.

[32] Ibid.

[33] DOE, 2008b.

[34] Western Governors’ Association. 2006. Geothermal Task Force Report. Clear and Diversified Energy Initiative.

[35] Tester et al., 2006.

[36] Ibid.

[37] Deloitte. 2008. Geothermal Risk Mitigation Strategies Report. Prepared for Department of Energy, Office of Energy Efficiency and Renewable Energy Geothermal Program.

[38] International Partnership for Geothermal Technology (IGPT). 2012. “About IGPT.” Accessed 22 August 2012.

[39] International Energy Agency (IEA). 2011. Geothermal Heat and Power Roadmap.

[40] DOE. 2009. “Recovery Act Announcement: President Obama Announces Over $467 Million in Recovery Act Funding for Geothermal and Solar Energy Projects.”

[41] DOE. 2012. “Geothermal Technologies Program - EGS Component R&D.”[field_project_area][0]=%2248%22

[42] DOE 2012. “Geothermal Technologies Program - EGS Systems Demonstration.”[field_project_area][0]=%2249%22

[43]Geothermal Energy Association (GEA). 2012. “Geothermal Basics Potential Use.” Accessed 22 August 2012.

[44] Bureau of Land Management (BLM). 2011. “Renewable Energy and the BLM: GEOTHERMAL.”

[45] Ledru, P. et al. 2007. “ENhanced Geothermal Innovative Network for Europe: the state-of-the-art.” Geothermal Resources Council Bulletin.

[46] GEA, 2012.

[47] IGPT, 2012.

[48] Ibid.

[49] DOE, 2008b.

[50] Deloitte, 2008.

[51]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.

[52] See footnote 9 in Tester et al., 2006.

[53] Center for Climate and Energy Solutions (C2ES). 2012a. “C2ES State Policy Map - Renewable & Alternative Energy Portfolio Standards.” Accessed 22 August 2012.

[54] C2ES. 2012b. Summary of the Clean Energy Standard Act.  

Syndicate content