Renewable Fuel Standard (RFS): Overview and Issues

Randy Schnepf
Specialist in Agricultural Policy

Brent D. Yacobucci
Section Research Manager

Federal policy has played a key role in the emergence of the U.S. biofuels industry. Policy measures include minimum renewable fuel usage requirements, blending and production tax credits, an import tariff, loans and loan guarantees, and research grants. One of the more prominent forms of federal policy support is the Renewable Fuel Standard (RFS)—whereby a minimum volume of biofuels is to be used in the national transportation fuel supply each year. This report describes the general nature of the RFS mandate and its implementation, and outlines some emerging issues related to the continued growth of U.S. biofuels production needed to fulfill the expanding RFS mandate, as well as the emergence of potential unintended consequences of this rapid expansion.

Congress first established the RFS with the enactment of the Energy Policy Act of 2005 (EPAct, P.L. 109-58). This initial RFS (referred to as RFS1) mandated that a minimum of 4 billion gallons be used in 2006, rising to 7.5 billion gallons by 2012. Two years later, the Energy Independence and Security Act of 2007 (EISA, P.L. 110-140) greatly expanded the biofuel mandate volumes and extended the date through 2022. The expanded RFS (referred to as RFS2) required the annual use of 9 billion gallons of biofuels in 2008, rising to 36 billion gallons in 2022, with at least 16 billion gallons from cellulosic biofuels, and a cap of 15 billion gallons for corn-starch ethanol.

In addition to the expanded volumes and extended date, RFS2 has three important distinctions from RFS1. First, the total renewable fuel requirement is divided into four separate, but nested categories—total renewable fuels, advanced biofuels, biomass-based diesel, and cellulosic biofuels—each with its own volume requirement. Second, biofuels qualifying under each category must achieve certain minimum thresholds of lifecycle greenhouse gas (GHG) emission reductions, with certain exceptions applicable to existing facilities. Third, all renewable fuel must be made from feedstocks that meet an amended definition of renewable biomass, including certain land use restrictions.

The Environmental Protection Agency (EPA) is responsible for establishing and implementing regulations to ensure that the nation’s transportation fuel supply contains the mandated biofuels volumes. EPA’s initial regulations for administering RFS1 (issued in April 2007) established detailed compliance standards for fuel suppliers, a tracking system based on renewable identification numbers (RINs) with credit verification and trading, special treatment of small refineries, and general waiver provisions. EPA rules for administering RFS2 (issued in February 2010) built upon the earlier RFS1 regulations and include specific deadlines for announcing annual standards, as well as greater specificity on potential waiver requests and RIN oversight.

Over the long term, the RFS is likely to play a dominant role in the development of the U.S. biofuels sector, but with considerable uncertainty regarding potential spillover effects in other markets and on other important policy goals. Emerging resource constraints related to the rapid expansion of U.S. corn ethanol production have provoked questions about its long-run sustainability and the possibility of unintended consequences in other markets as well as on the environment. Questions also exist about the ability of the U.S. biofuels industry to meet the expanding mandate for biofuels from non-corn sources such as cellulosic biomass materials, whose production capacity has been slow to develop, or biomass-based biodiesel, which remains expensive to produce owing to the relatively high prices of its feedstocks. Finally, considerable uncertainty remains regarding the development of the infrastructure capacity (e.g., trucks, pipelines, pumps, etc.) needed to deliver the expanding biofuels mandate to consumers.


Date of Report: March 14, 2013
Number of Pages: 35
Order Number: R40155
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Historical Development of the Windmill

The wind turbine has had a singular history among prime movers. Its genesis is lost in antiquity, but its existence as a provider of useful mechanical power for the last thousand years has been authoritatively established for recognition as historical fact by most professional historians of technology. The windmill, which once flourished along with the water wheel as one of the two prime movers based on the kinetic energy of natural sources, reached its apogee of utility in the seventeenth and eighteenth centuries. Its use then began to decline, as prime movers based on the thermal energy from the combustion of fuel took precedence. Steam engines, steam turbines, and oil and gas engines provided more powerful and more compact machines, adaptable to a multitude of uses other then just the grinding of grain and the pumping of water. These new heat engines also were continuously available rather then subject tot he vagaries of nature, and they could be located at the job site rather the requiring that the job be brought to them.


Date of Report: March 6, 2013
Number of Pages: 47
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas

Marc Humphries
Specialist in Energy Policy

In 2012, oil prices ranged from $80 to $110 per barrel (West Texas Intermediate spot price) and remain high in early 2013. Congress is faced with proposals designed to increase domestic energy supply, enhance security, and/or amend the requirements of environmental statutes. A key question in this discussion is how much oil and gas is produced each year and how much of that comes from federal and non-federal areas. On non-federal lands, there were modest fluctuations in oil production from fiscal years (FY) 2008-2010, then a significant increase from FY2010 to FY2012 increasing total U.S. oil production by about 1.1 million barrels per day over FY2007 production levels. All of the increase from FY2007 to FY2012 took place on non-federal lands, and the federal share of total U.S. crude oil production fell by about seven percentage points.

Natural gas prices, on the other hand, have remained low for the past several years, allowing gas to become much more competitive with coal for power generation. The shale gas boom has resulted in rising supplies of natural gas. Overall, U.S. natural gas production rose by four trillion cubic feet (tcf) or 20% since 2007, while production on federal lands (onshore and offshore) fell by about 23% and production on non-federal lands grew by 40%. The big shale gas plays are primarily on non-federal lands and are attracting a significant portion of investment for natural gas development.

The number of producing acres may or may not be a function of how many acres are leased, and the amount of acres leased may or may not correlate to the amount of production, but in recent years, some members of Congress have proposed a $4/acre lease fee for non-producing leases. This proposal grew out of the efforts to open more public land and water (offshore) for oil and gas drilling and development when gasoline prices spiked in 2006-2008. Some in Congress noted that there were many leases they believed were not being developed in a timely fashion, while at the same time, others in Congress were pushing for greater access to areas off-limits (such as the Arctic National Wildlife Refuge (ANWR) and areas under a leasing moratoria offshore). Higher rents for offshore leases were imposed by the Secretary of the Interior in 2009 to discourage holding unused leases and to move more leases into production if possible.

Another major issue that the 113th Congress may seek to address is streamlining the processing of applications for permits to drill (APDs). Some members contend that this would be one way to help boost energy production on federal lands. After a lease has been obtained, either competitively or non-competitively, an application for a permit to drill (APD) must be approved for each oil and gas well. Despite the new timeline for review (under the Energy Policy Act of 2005, P.L. 109-58), it took an average of 307 days for all parties to process (approve or deny) an APD in 2011, up from an average of 218 days in 2006. The difference, however, is that in 2006 it took the BLM an average of 127 days to process an APD, while in 2011 it took BLM 71 days. In 2006, the industry took an average of 91 days to complete an APD, but in 2011, industry took 236 days. The BLM stated in its FY2012 and FY2013 budget justifications that overall processing times per APD have increased because of the complexity of the process.


Date of Report: March 7, 2013
Number of Pages: 13
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U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas

Marc Humphries
Specialist in Energy Policy

In 2012, oil prices ranged from $80 to $110 per barrel (West Texas Intermediate spot price) and remain high in early 2013. Congress is faced with proposals designed to increase domestic energy supply, enhance security, and/or amend the requirements of environmental statutes. A key question in this discussion is how much oil and gas is produced each year and how much of that comes from federal and non-federal areas. On non-federal lands, there were modest fluctuations in oil production from fiscal years (FY) 2008-2010, then a significant increase from FY2010 to FY2012 increasing total U.S. oil production by about 1.1 million barrels per day over FY2007 production levels. All of the increase from FY2007 to FY2012 took place on non-federal lands, and the federal share of total U.S. crude oil production fell by about seven percentage points.

Natural gas prices, on the other hand, have remained low for the past several years, allowing gas to become much more competitive with coal for power generation. The shale gas boom has resulted in rising supplies of natural gas. Overall, U.S. natural gas production rose by four trillion cubic feet (tcf) or 20% since 2007, while production on federal lands (onshore and offshore) fell by about 33% and production on non-federal lands grew by 40%. The big shale gas plays are primarily on non-federal lands and are attracting a significant portion of investment for natural gas development.

The number of producing acres may or may not be a function of how many acres are leased, and the amount of acres leased may or may not correlate to the amount of production, but in recent years, some members of Congress have proposed a $4/acre lease fee for non-producing leases. This proposal grew out of the efforts to open more public land and water (offshore) for oil and gas drilling and development when gasoline prices spiked in 2006-2008. Some in Congress noted that there were many leases they believed were not being developed in a timely fashion, while at the same time, others in Congress were pushing for greater access to areas off-limits (such as the Arctic National Wildlife Refuge (ANWR) and areas under a leasing moratoria offshore). Higher rents for offshore leases were imposed by the Secretary of the Interior in 2009 to discourage holding unused leases and to move more leases into production if possible.

Another major issue that the 113th Congress may seek to address is streamlining the processing of applications for permits to drill (APDs). Some members contend that this would be one way to help boost energy production on federal lands. After a lease has been obtained, either competitively or non-competitively, an application for a permit to drill (APD) must be approved for each oil and gas well. Despite the new timeline for review (under the Energy Policy Act of 2005, P.L. 109-58), it took an average of 307 days for all parties to process (approve or deny) an APD in 2011, up from an average of 218 days in 2006. The difference, however, is that in 2006 it took the BLM an average of 127 days to process an APD, while in 2011 it took BLM 71 days. In 2006, the industry took an average of 91 days to complete an APD, but in 2011, industry took 236 days. The BLM stated in its FY2012 and FY2013 budget justifications that overall processing times per APD have increased because of the complexity of the process.


Date of Report: Febrary 28, 2013
Number of Pages: 13
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Keystone XL Pipeline Project: Key Issues

Paul W. Parfomak
Specialist in Energy and Infrastructure Policy

Robert Pirog
Specialist in Energy Economics

Linda Luther
Analyst in Environmental Policy

Adam Vann
Legislative Attorney

In May 2012, Canadian pipeline company TransCanada reapplied to the U.S. Department of State for a Presidential Permit to build the Keystone XL pipeline. The pipeline would transport crude oil from the oil sands region of Alberta, Canada, to the existing Keystone Pipeline System in Nebraska. It also could accept U.S. crude from the Bakken oil fields in Montana and North Dakota. A second segment of the Keystone XL pipeline system, the Gulf Coast Project, is proceeding separately to connect existing pipeline facilities in Oklahoma to refineries in Texas. When completed, the entire Keystone XL pipeline system would ultimately have capacity to transport 830,000 barrels of crude oil per day to U.S. market hubs. TransCanada submitted the May 2012 permit application after its 2008 Keystone XL permit application was denied.

The State Department has jurisdiction over the Keystone XL pipeline’s approval because it would cross the U.S. border. Before it can approve such a permit, the department must determine that the project is in the “national interest,” accounting for potential effects on the environment, economy, energy security, and foreign policy, among other factors. Environmental impacts are considered under the National Environmental Policy Act, as documented in an Environmental Impact Statement (EIS). For the 2008 permit application, a final EIS was issued in August 2011, followed by a public review period. Largely in response to public comments and efforts by the state of Nebraska, the State Department determined that it needed to examine alternative pipeline routes that would avoid the environmentally sensitive Sand Hills region of Nebraska, a sand dune formation with highly porous soil and shallow groundwater that recharges the Ogallala aquifer.

The Temporary Payroll Tax Cut Continuation Act of 2011 (P.L. 112-78) required the Secretary of State to approve or deny the original 2008 project application within 60 days. On January 18, 2012, citing insufficient time under this deadline to properly assess the reconfigured project, the State Department denied the Keystone XL permit. Since then, TransCanada has worked with Nebraska officials to identify a pipeline route avoiding the Sand Hills. Its May 2012 permit application reflects that effort. The State Department has begun the NEPA process anew, but will largely supplement the August 2011 final EIS to include analysis of the new route in Nebraska, as well as analysis of any significant environmental issues or information that has become available since August 2011. The department estimates that it will determine whether to approve or deny the new Presidential Permit by early 2013.

The 112th Congress debated numerous legislative options addressing the Keystone XL pipeline. The North American Energy Access Act (H.R. 3548) would have transferred permitting authority for the Keystone XL pipeline project to the Federal Energy Regulatory Commission, requiring issuance of a permit within 30 days of enactment. Several other bills (H.R. 3811, H.R. 4000, H.R. 4301, S. 2041, and S. 2199) would have approved immediately the 2008 permit application filed by TransCanada. A House bill (H.R. 6164), the Domestic Energy and Jobs Act (S. 3445), and S.Amdt. 2789 would have eliminated the Presidential Permit requirement for the reconfigured Keystone XL pipeline as proposed in TransCanada’s permit application filed on May 4, 2012. S. 2100 and H.R. 4211 would have suspended sales of petroleum products from the Strategic Petroleum Reserve until issuance of a Presidential Permit for the Keystone XL project. H.R. 3900 sought to ensure that crude oil transported by the Keystone XL pipeline, or resulting refined petroleum products, would be sold only into U.S. markets. To date, no Keystone XL legislation has been proposed in the 113th Congress but the issues surrounding the Presidential Permit remain largely the same.


Date of Report: January 24, 2013
Number of Pages: 42
Order Number: R41668
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