                 Carbon Dioxide Pipelines in the United States

                             Contract EP-W-10-055
                              Work Assignment 27
                        Technical Directive 3, Part 1

                     Submitted by The Cadmus Group, Inc.
Under Subcontract to Eastern Research Group, Inc.
Carbon Dioxide Pipelines in the United States

1.0 Introduction
   Enhanced oil recovery is the largest use of carbon dioxide in the United States, exceeding the use for food grade carbon dioxide by a factor of ten (Interstate Oil and Gas Compact Commission (IOGCC), 2010). This carbon dioxide is transported from sources to oil fields for injection by means of pipeline. Pipelines are favored for carbon dioxide transport because they are the easiest means to transport large volumes of carbon dioxide the distances required to the oil fields. While transport is possible by tanker trucks or ships, transporting the volumes required for enhanced oil recovery would require an inordinate number of vehicles, would require significant storage, and would make continuous delivery of carbon dioxide difficult.
   Increased interest in geologic sequestration (GS) of carbon dioxide will significantly increase the need for carbon dioxide pipelines. Like oil recovery, pipelines would be the transportation mode of choice to enable delivery of carbon dioxide continuously at volumes and pressures adequate for GS injection. Estimates of the required mileage of pipeline to meet sequestration needs under a carbon regulation scenario range from 11,000 miles to 66,000 miles (Carbon Sequestration Leadership Forum, undated; IOGCC, 2010). This will represent a large increase in the total mileage of carbon dioxide pipelines. To ensure the safety of these future pipelines, it is instructive to review the current state of knowledge regarding carbon dioxide pipelines.
   This report will review the current state of knowledge of carbon dioxide pipelines in the United States, and provide the following information:
      * An overview of the existing pipeline network, including amounts of carbon dioxide shipped, miles of pipeline, and a description of the pipelines.
      * A review of various considerations for pipeline construction including materials, size, and other guidelines.
      * Costs of pipeline projects including capital, operations and maintenance, and other fees.
      * Pipeline safety, including regulations and past incidents.
      * A discussion of planned future pipelines.

2.0 Pipeline Statistics
   Pipeline safety is regulated by the Pipeline Hazardous Materials and Substance Administration (PHMSA), which is a branch of the Department of Transportation. The PHMSA keeps statistics on all pipelines transporting hazardous substances. Although carbon dioxide is not considered a hazardous substance, it is regulated with hazardous liquids, as the construction requirements for supercritical carbon dioxide are similar to those for hazardous liquids (e.g., petroleum products) pipelines. Statistics are kept on all transportation pipelines. The segments covered would include pipelines from the source up to the individual oil fields. Feeder lines to individual wells are not included in PHMSA statistics. Statistics are kept according to operator and not by pipeline. Therefore, PHMSA statistics do not enable analysis by pipeline or source. The following sections describe the statistics compiled by PHMSA supplemented by other sources to describe the current carbon dioxide pipeline situation.
      2.1 Carbon Dioxide Transported
      Table 1 gives the PHMSA statistics for carbon dioxide transported for 2010, the most recent year available. The table lists 25 operators transporting nearly 2 trillion barrel-miles of carbon dioxide. As a comparison, the 2008 statistics as cited in the Assessment of the Potential Costs, Benefits, and Other Impact of the Conditional Exclusion from the RCRA Definition of Hazardous Waste for CO2 Streams Managed in UIC Class VI Wells for the Purposes of Geologic Sequestration (EPA, 2011) lists 26 operators (Genesis is listed twice) transporting 34 billion barrel-miles of carbon dioxide. It is not known whether Transpetco, the operator not reported in the 2010 statistics is inactive or if operation of that pipeline was assumed by another company. The 2010 values represent a significant increase from the 2008 values.
      The largest shipper of carbon dioxide was Exxon/Mobil with nearly 1.8 trillion barrel-miles of carbon dioxide transported. The next biggest shippers of carbon dioxide in 2010 were Kinder Morgan, Enmark, and Bravo. All of the major operators saw significant increases. Exxon/Mobil saw a nearly 15 percent increase. Kinder Morgan nearly tripled its barrel-miles transported; Enmark went from just over 13 thousand barrel-miles to over 52 billion barrel-miles. Bravo saw a slight increase from 19.1 to 19.5 billion barrel-miles. It is possible there is some skew in the increase in delivery of carbon dioxide since results are reported in barrel-miles. The increase may represent increased volume delivered or it could represent increased distances of delivery. Most likely, both factors play into the significant increase.
      Table 1: Barrel Miles of Carbon Dioxide Transported in 2010

      Source: PHMSA (2010)
      2.2 Miles of Pipe
      The transport of nearly 2 trillion barrel-miles of carbon dioxide necessitates a significant pipeline network. The total miles of pipe by operator is shown in Table 2.  PHMSA statistics indicate there were 4,477.6 miles of pipeline in 2010. This is an increase in approximately 200 miles over the 2008 statistics. Much of the increase was an addition of about 330 miles of pipeline for Denbury Offshore. They are in the middle of a pipeline project to bring carbon dioxide from sources in Mississippi and Louisiana to the Gulf Coast of Texas. The increase by Denbury was offset by the loss of the Transpetco pipeline from the 2010 data. Several other operators experienced small changes in their total pipe. Some of these changes may represent transfers of ownership rather than building or retiring of pipeline.
      Table 2.  Miles of Pipeline by Operator
      Source:  PHMSA (2010)
      * These pipelines were not included in the 2010 PHMSA data but appeared in previous years or were listed in other sources, their current status is unknown.
      In terms of miles of pipe operated, the largest operators are Kinder Morgan, Bravo, and Denbury. These three operators represent over half of the carbon dioxide pipelines in service.

      2.3 Map
      Figure 1 displays a map of current known and planned carbon dioxide pipelines in the United States. The date of the map is unknown, but the Denbury-Green pipeline shown as planned has been completed. The map shows the main transmission carbon dioxide pipelines in the United States. It does not show small lines to individual fields or wells.
Figure 1:  Map of Carbon Dioxide Pipelines in the United States

      Source: Marston Law accessed at: http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm on 5/16/2012

      2.4 Description of Pipelines
      There are essentially three main carbon dioxide pipeline networks in the US, along with several other carbon dioxide pipelines that supply individual fields. This section includes brief descriptions of each pipeline including its sources and sinks.

      West Permian Basin
      The largest and oldest carbon dioxide pipeline network is in the West Permian Basin in Western Texas and Eastern New Mexico. Most of the pipelines feed from sources into a carbon dioxide hub located near Denver City, TX. Carbon dioxide is distributed from there to several pipelines feeding oil recovery fields in Western Texas, New Mexico, and Oklahoma. The first pipeline in both this basin and the nation was the Canyon Reef pipeline, carrying carbon dioxide from several gas plants in West Texas to the SACROC oil field, and is operated by Kinder Morgan. The Bravo Pipeline carries carbon dioxide from the Bravo Dome in Colorado into the Texas hub and is jointly owned by Occidental, XTO, and Kinder Morgan. The Sheep Mountain Pipeline carries carbon dioxide from a natural source in Colorado and connects into the central hub near Denver City, TX. The Cortez Pipeline extends from the McElmo Dome in Utah to the hub in Texas and is operated by Kinder Morgan. Another pipeline from a Doe Canyon natural source in Utah also connects into the Cortez Pipeline. From the Denver City hub, pipelines extend to several different oil fields including the Postle Field, Comanche Creek Field, North Ward Estates Field, and fields in Cochran, Hockley, and Yoakum County Texas. Operators active in the Permian basin carbon dioxide pipelines include Kinder Morgan, Exxon/Mobil, XTO, Occidental, Hess, Trinity Pipeline, and Apache. In addition, Sandridge CO2 also operates a pipeline from the Pike's Peak gas plant in Texas to the Val Verde oil fields also in Texas.
      LaBarge Pipeline
      The second major area of carbon dioxide supply is from the Exxon/Mobil Shute Creek gas plant in Sublette County, Wyoming. The plant is currently capable of producing 365 million cubic feet of carbon dioxide a day (Oil and Gas Journal, 2010). Gas is shipped from the plant to oil fields in Wyoming and Colorado. Oil fields supplied by the LaBarge plant include Beaver Creek, Rangeley, Salt Creek, and Monell. Operators active in this area include Exxon/Mobil, Anadarko, Chevron, and Devon.
      Jackson Dome Area
      The last major pipeline network carries carbon dioxide from the Jackson Dome in Mississippi. It currently extends to the Hastings Oil Field near Houston, Texas. Denbury has also negotiated, or is in the process of negotiating, deals with several gas plants and power plants to supply gas to this pipeline as well. Denbury is the main operator in this area with Enmark being active as well. This pipeline was also used to deliver carbon dioxide to the Cranfield Department of Energy (DOE) Carbon Capture and Storage (CCS) demonstration site in Mississippi.
      Dakota Gasification Pipeline
      While the Dakota Gasification Pipeline has a single source and sink, it is still one of the major carbon dioxide pipelines. Completed in the 1990s, it delivers carbon dioxide from the Dakota Gasification Plant in North Dakota to the Weyburn oil field in Canada. The pipeline stretches over 200 miles, with about 167 of those miles inside the United States.
      Chapparal Energy Pipelines
      Chapparal Energy also runs several pipelines from dedicated sources to oil fields. One such pipeline runs from the Arkalon ethanol plant in Kansas to the Farnsworth Unit in Oklahoma. Another line runs from a fertilizer plant in Texas to the Camrick Unit in Oklahoma.
      Enid Pipeline
      Merit Energy runs a carbon dioxide pipeline that runs from the Enid Fertilizer plant in Enid, Oklahoma to the Purdy oil field also in Oklahoma.
      White Frost Pipeline
      Although it is not listed in the current PHMSA statistics, there is a carbon dioxide pipeline that runs from the DTE gas plant in Michigan to some Niagaran Reef oil formations in Michigan. This pipeline operates periodically, depending on the economics of oil recovery using carbon dioxide. The pipeline also has capabilities to deliver to a DOE CCS demonstration project in Michigan.
3.0 Pipeline Construction
   Carbon dioxide is pumped in the supercritical state in order to maximize the efficiency of pumping large amounts of carbon dioxide. The supercritical state has a higher density and therefore allows larger masses of carbon dioxide in the same diameter pipeline. Because the supercritical state behaves like a liquid, it can also be transported using pumps instead of compressors. Carbon dioxide can also be corrosive when combined with water. Some impurities found in carbon dioxide streams may also be corrosive. Pipelines must be designed to handle the supercritical state of the carbon dioxide as well as potential corrosivity. The following section discusses various design specifications typical of carbon dioxide pipelines.
      3.1 Pipe Material
      When selecting pipe materials, the pressure experienced and the potential corrosivity are taken into consideration. Steel is sufficient to withstand the pressures required to transport supercritical carbon dioxide. Carbon steel, however, can be corroded by carbon dioxide in the presence of water. Stainless steel is not as susceptible to corrosion as carbon steel, but is considerably more expensive. According to PHMSA regulations, all carbon dioxide pipelines must be steel, with the exception of some grandfathered pipelines (49 CFR 195.112). PHMSA data indicate that all existing pipeline is steel pipe. The data do not differentiate between carbon steel and stainless steel. All but 9 miles of the nearly 4,500 miles of pipeline is coated and cathodically protected to prevent corrosion. Over 3,000 miles of that pipe were constructed using high frequency electric resistance welding. Data is also supplied on the date of construction of pipelines. Figure 3 shows the current inventory of pipeline by date of construction.
      Figure 3. Percent Pipeline by Date Constructed

      Source:  PHMSA (2010)
      As Figure 3 shows, carbon dioxide pipeline construction reached a peak in the 1980s. Significant pipeline construction continues, however, and additional pipelines are being planned for the future. Further discussion of planned pipeline projects is included in Section 6.0. The first pipeline built explicitly for carbon dioxide transport for oil recovery was constructed in the 1970s. The pipelines that were constructed before that date were most likely originally constructed for other purposes and converted for carbon dioxide transport. Such transfer of purpose of pipelines has occurred. For example, Denbury purchased a natural gas pipeline in Louisiana and converted it to carbon dioxide transport (FERC, 2006). There are also cases of the opposite occurring, such as Bravo converting a portion of its Slaughter carbon dioxide pipeline to a natural gas gathering pipeline (Texas RRC, 2012). It should be noted that pipelines cannot be transferred to and from carrying natural gas without approval by the Federal Energy Regulatory Commission (FERC), which regulates this activity and may require public hearings.
      3.2 Pipe Sizes and Depth
      The PHMSA data also includes information on the size of pipe. Pipeline size depends on the amount of carbon dioxide being transferred and the pressure and temperature of the pipeline. Pipeline sizes range from less than 4 inches to 30 inches in diameter. Generally, the smaller diameters are for lines to specific oil fields. The larger lines are generally the transmission lines. Figure 4 shows the percent of total pipeline represented by each size diameter.
      Figure 4 Percent of Carbon Dioxide Pipeline by Diameter (inches)

   Source:  PHMSA (2010)
      The most common pipe sizes are 20 and 24 inches, representing nearly 20 percent of the total length of pipeline each. Pipelines of 8, 16, and 30 inches are also common.
      Federal regulations require most pipe to be buried (49 CFR 195.248). Minimum burial depths required by the regulation range from 30mm to 48mm, but actual burial depths are likely much greater. PHMSA does not have statistics on depth of burial. Some data was available in the incident reports provided by PHMSA as well as some project reports for specific pipelines. Depths were generally between 3 and 6 feet but could be as deep as 100 feet in areas such as river crossings. Depth is likely to vary depending on local temperature and geology, as well as factors such as road or stream crossings.
      3.3 Construction Guidelines
       As mentioned previously, pipelines must be designed to carry the appropriate amount of carbon dioxide at supercritical pressures, which are greater than about 1,100 psi (Barrie et al., 2004). Pipeline diameter is determined by the desired flow and the pressure of the pipeline.
      PHMSA regulations specify construction standards for carbon dioxide pipelines. The regulations are generally performance standards and also incorporate industry standards such as API and ASME standards.  Carbon dioxide pipelines must be designed for the pressure the pipe experiences and pipeline must be compatible with the fluids it will carry (49 CFR 195.4, 108, 110).  One major concern with carbon dioxide pipelines is longitudinal fractures, which can propagate quickly over long distances. Pipelines must be designed to prevent such fractures (49 CFR 195.111). Preventing such fractures can be achieved by specifying the proper thickness and toughness. Mechanical fracture arrestors are also often installed along the pipeline to prevent cracks from propagating over long distances if they start (Cosham and Eiber, 2007). Valves, hooked to automatic control systems, are also installed to enable isolation of leaks should they occur. They are required at pump stations, surface water crossings, laterals, and sensitive areas (49 CFR 195.260). Generally, pipelines would be buried at depths shallow enough to be above the saturated zone of the soil, so groundwater would not be a concern. Too many valves, however, can be problematic, as they can themselves fail and become sources of leaks (see Section 5.2). Another consideration in transporting supercritical gases is that supercritical gases will rapidly expand and cool if a loss of pressure occurs. Temperatures can drop quickly enough that the carbon dioxide can freeze. Therefore, carbon dioxide pipelines must be designed to resist very low temperatures (40 CFR 195.102). Theoretically the temperature could get as low as the freezing point of carbon dioxide which is -78.5 [o]C at atmospheric pressure.
      Corrosion control is another concern. Carbon dioxide mixed with water can be corrosive. Other potential impurities in carbon dioxide streams such as nitrogen oxides and hydrogen sulfide can also be corrosive. The DeWaard/Milliams nomograph can be used to predict corrosion of steel based on carbon dioxide concentration and temperature. Typically, carbon dioxide streams are dehydrated and carbon steel is used for pipelines. A typical value of 50 ppm or less water content is a common requirement for carbon dioxide transported in pipelines (Fredet et al., 2007). While carbon steel is often used for carbon dioxide pipes, stainless steel may be required for turbulent areas near valves and pumps (Barrie et al., 2004). As noted above, most carbon dioxide pipelines also use cathodic protection and lining to prevent corrosion problems.
      3.4 Quality Considerations
      The composition of the carbon dioxide stream provides several important considerations for pipeline design. These include transport properties of the stream, corrosivity, and viability of the carbon dioxide for its final use. Mixtures of gases can often have very different properties from pure gases. This can be important for designing pipelines. For example, combined with water, carbon dioxide can form solid hydrates at low temperatures and high pressures. The solid hydrates can clog pipelines. These hydrates can form at temperatures as high as 10[o]C (Fredet et al., 2007). Impurities can also alter the critical temperature and pressure of the carbon dioxide being transported. Raising the critical pressure and temperature will require higher operating pressures and therefore greater costs. Lowering the critical temperature and pressure may help reduce costs. Nitrogen oxides can lower the critical pressure and temperature of the carbon dioxide stream. Hydrogen gas, on the other hand, can raise the critical temperature and pressure (Seevam et al., 2007). Nitrogen and methane may also increase the critical pressure and require higher operating pressures (IOGCC, 2010).
      Water is the most significant component that can increase the corrosivity of carbon dioxide streams, and must be limited to avoid significant corrosion or expensive materials. Hydrogen sulfide is corrosive to pipeline materials and is toxic. Additional requirements are often imposed on pipelines with significant sulfide, although several pipelines do transport higher levels of hydrogen sulfide. Like carbon dioxide, sulfur and nitrogen oxides may also be corrosive in the presence of water. Oxygen can cause corrosion and is often specified to be below 10 to 20 ppm to prevent corrosion (IOGCC, 2010). Corrosion can be prevented or mitigated by limiting corrosive impurities and by specifying corrosion resistant materials and cathodic protection.
      The last factor that can affect the quality of carbon dioxide shipped in pipelines is the end use. For existing carbon dioxide pipelines, the end use is enhanced oil recovery. Some impurities can change the miscibility of carbon dioxide with oil and therefore change its effectiveness in recovering oil. Nitrogen gas decreases the miscibility of carbon dioxide with oil and therefore decreases its value for recovering oil. Many pipelines have maximum specifications for nitrogen gas because of this. Sulfide, sulfur oxides, and nitrogen oxides, on the other hand increase the miscibility and make carbon dioxide more attractive for enhanced oil recovery.
      Table 3 shows the purity of carbon dioxide stream specifications in some existing pipelines. The specifications represent agreed upon limits of the concentrations allowed in the pipelines. The table shows that current carbon dioxide streams generally contain 95 percent or more carbon dioxide. Common impurities can include methane, hydrogen sulfide, and nitrogen.
      Table 3.  Carbon Dioxide Stream Specifications for Several Existing Pipelines
Pipelines
Carbon Dioxide Content (Percent)
Methane Content (Percent)
Higher Hydrocarbon Gases (Percent)
Nitrogen Content (Percent)
Hydrogen Sulfide Content (Percent)
Canyon Reef Carriers
                                      95
                                       5
                                       -
                                   < 0.5
                                     0.01
Central Basin Pipeline
                                     98.5
                                      0.2
                                       -
                                      1.3
                                       -
Sheep Mountain Pipeline
                                     96.8
                                      1.7
                                      0.6
                                      0.9
                                       -
Bravo Pipeline
                                     99.7
                                       -
                                       -
                                      0.3
                                       -
Weyburn
                                      96
                                       -
                                      2.3
                                     0.03
                                      0.9
      Source:  Seevam et al., 2007

4.0 Costs
   Several costs comprise the cost of transporting carbon dioxide by pipeline. These include the capital cost to construct the pipeline, costs to operate and maintain the pipeline, and fees charged by either state regulators for permitting of the pipeline or fees charged by pipeline operators for use of the pipeline.
      4.1 Construction Costs
      Capital costs for a pipeline will depend on many factors. These include the capacity of the pipeline, pipeline materials required, and terrain. Table 4 shows costs compiled by the Interstate Oil and Gas Compact Commission (IOGCC) from several existing pipelines, including some estimates compiled by Federal Energy Regulatory Commission (FERC) and the Oil and Gas Journal. The costs represent total capital costs for the project including installation divided by the length and diameter of the pipeline. Costs in 2009 ranged from about $27,000 per inch-mile of pipeline to nearly $94,000 per inch-mile. The costs are normalized by length and diameter of the pipeline as these are the biggest factors in determining pipeline cost. For example a cost model from Carnegie Mellon University, based on natural gas pipeline costs, found a relationship where cost for a pipeline in the Midwest was:
      Cost = 10[3.112]*L[0.901]*D[1.590]
      Where L is the length of the pipeline and D is the diameter (Rubin et al., 2008). It can be seen that the diameter is the biggest factor, while length is also important. While depth may have an effect on costs, it was not considered in any of the cost models examined in the scope of this paper (MIT, 2007; Rubin et al., 2008). The only consideration of depth were general statements that rugged terrain and urbanized areas can increase costs.
      Table 4 Pipeline Capital Costs
Pipeline
Location
Cost (2009$/in-mile)
Dakota Gasification
North Dakota
46,500
Hall-Gurney
Kansas
26,650
Coffeyville Resources
Kansas
54,000  -  83,000
Green Pipeline
Louisiana, Mississippi
93,750
Oil and Gas Journal Average Cost
National Estimate
64,900
FERC data
National Estimate
39,400
      Source:  IOGCC 2010
      It should be noted that the cost of the steel pipe is approximately 15 to 35 percent of the total pipeline cost (IOGCC, 2010). This is significant, as the price of steel pipe greater than 24 inches has risen from $500 per meter in 2000 to over $1,400 per meter in 2007 (CRS, 2008).
      4.2 Operating Costs
      Operating costs include power costs for operating pumps and compressors, labor costs for pipeline operation and maintenance, and material costs for maintenance. Table 5 shows operating costs for several pipelines.
      Table 5  Pipeline Operation and Maintenance Costs
Pipeline
Pipeline Length and Size
Year
O&M Costs ($/yr)
Source
Ohio Network (proposed)
450 miles
12 inch diameter
2008
2,300,000
Pew Charitable Trust, 2008
Russell, Kansas Geosequestration/EOR Project
7 miles
2007
1,900,000  -  2,300,000
Carr & Dubois, 2007
Estimated costs for IGCC pipeline
300 miles
2003
480,000  -  720,000
Bock et al., 2003

      Costs vary depending on length of the pipeline, the pressure at which it operates, and complexity of operations. A study by Pew Charitable Trust for a proposed carbon dioxide pipeline in Ohio estimated an annual cost of $2.3 million/year for operating costs of a 450 mile pipeline (Pew Charitable Trust, 2008). Several studies have estimated total costs of transporting carbon dioxide by pipeline. The costs include annualized capital costs and operation and maintenance costs. One study by the Massachusetts Institute of Technology estimated costs for a 100 kilometer pipeline from $1.21 per ton to $11.16 per ton with an average of $3.82 per ton for carbon dioxide pipelines to oil reservoirs. An NETL study estimated $0.55 per ton for carbon dioxide pipelines from carbon dioxide domes to oil fields in Texas (IOGCC, 2010). An IOGCC report estimated $1.25 per thousand cubic feet of carbon dioxide from natural sources and $1.30 to $1.75 for carbon dioxide from natural gas plants (IOGCC, 2010).
      4.3 Fees
      There are several kinds of fees that may apply to carbon dioxide pipelines. First, fees may be administered by PHMSA or States for pipeline permitting. PHMSA assesses a user fee for all hazardous liquid pipelines. That fee is $109.91 per mile and is used to offset costs of PHMSA and state programs. Usage fees are also charged by the companies that own the pipeline. Such fees would not apply in cases where the source, pipeline, and final use of the carbon dioxide are all owned by the same entity. It does apply, however, to companies that own and operate pipelines and transport carbon dioxide to other companies operating oil fields. Generally, such contracts are negotiated between the pipeline company and the purchaser of the carbon dioxide. Such agreements may contain provisions linking fees to the price of oil and the pressure or quality at which the carbon dioxide is delivered. Some carbon dioxide pipelines are considered common carriers, meaning they must transport carbon dioxide from any source for the same published price. The Bureau of Land Management has required many carbon dioxide pipelines crossing federal lands to be common carriers. The State of Texas requires pipelines to be common carriers if they want eminent domain rights in the State. While being a common carrier usually requires publishing of rates, administrative bodies have not required carbon dioxide common carriers to publically post their rates. One source found that carbon dioxide transport fees ranged from $2 to $3/ton for a pipeline of 50 to 100 miles in length (Bergman and Winter, 1997). Other fees may also apply such as State, County, or Local fees. However, no listing of such costs or fees was found within the scope of this paper.
5.0 Pipeline Safety
   Pipeline safety is a prime concern with carbon dioxide pipelines and is regulated by the PHMSA and State regulatory agencies. The prime concern is that carbon dioxide is an asphyxiant and is heavier than air. Therefore, carbon dioxide may leak and accumulate in poorly ventilated, low lying areas and potentially build up to dangerous or lethal levels. Another concern is that if high pressure pipelines fail catastrophically, the rapid depressurization can cause solid carbon dioxide to be ejected at high rates causing potential damage to property and life. While there are significant safety concerns with carbon dioxide pipelines, pipelines have operated safely for decades. The following sections include records of significant safety incidents and a summary of state and federal regulations governing pipeline safety.
      5.1       Regulations
      Pipeline safety is regulated by the Department of Transportation through the PHMSA. Regulations governing carbon dioxide pipelines fall under 49 CFR 195. The regulations cover topics such as material selection, construction requirements, pressure limits, and reporting requirements. Many of the requirements are either performance standards, such as requiring pipelines to be compatible with the fluids they carry (e.g. 49 CFR 195.4), or refer to other standards. A total of 40 standards are incorporated into the pipeline regulations by reference, these are listed in Appendix A. The federal regulation provides that States that have standards at least as stringent as the federal standard and have effective enforcement programs oversee pipelines within their state if their regulations are at least as strict as federal standards. For the most part, states have adapted the federal regulations verbatim. A brief review of the regulations found that where they did vary from federal requirements they were often to provide more specific requirements or requirements for local conditions. For example, New Mexico specifies certain types of leak detection tests. Other differences between state and federal laws can include things such as lower reporting limits for leaks or requiring more frequent inspection for high risk pipelines. Generally though, most states follow the federal regulations.
      Agreements between States and the Federal Office of Pipeline Safety (OPS) dictate who performs inspection and enforcement activities within each state. A brief review of state agreements was conducted for states that have existing or planned carbon dioxide pipelines. In many states, OPS regulates and inspects all hazardous liquid pipelines, including carbon dioxide pipelines. These states include: Colorado, Illinois, Kansas, Michigan, Montana, North Dakota, Ohio, Utah, and Wyoming. Another common agreement is for OPS to regulate interstate pipelines and the state to regulate intrastate pipelines. This type of agreement is in place in Indiana, Louisiana, New Mexico, Oklahoma, and Texas. In Arizona and California, all pipelines are regulated by the state. Pipelines contained entirely on the property of the pipeline owner are not covered by Federal OPS or State regulations. Some smaller pipelines, such as those extended from the main line to an individual injection well may also not fall under federal regulations. Such pipelines, however, would not be totally unregulated. OSHA standards may apply to some aspects of pipeline construction and operation. For example 49 CFR 192 covers transportation of natural gas and other gas by pipeline. OSHA also has regulations that would apply during pipeline construction. Construction will also likely be regulated by local authorities and may require meeting industry standards, plan review, and construction inspections. For example, if the pipeline is for a sequestration project, Class VI UIC regulations require submittal of construction plans which would include surface facilities such as pipelines (40 CFR 146.82(a)(11). ASME B31.4 is a standard often used for pipeline construction. While local construction permits most likely require meeting such standards a review of such codes is beyond the scope of this paper. Insurance policies may also require meeting design standards and following best management practices. A study for the Pennsylvania Department of Conservation and Natural Resources stated that insurance was readily available for carbon dioxide pipelines and many pipelines had such insurance (Tetra Tech, 2009). In order to set premiums for an insurance policy insurance companies typically perform a risk assessment of the project. The risk assessment would include items such as age and design of the pipeline, whether increased design standards were used in high risk areas such as river crossings, company operating and maintenance procedures, and existing emergency and response plans (Radevsky and Scott, 2004).
      5.2 Incidents
      PHMSA requires reporting of any incidents that release more than 5 gallons of supercritical carbon dioxide (49 CFR 195.50). Table 6 shows a list of incidents on carbon dioxide pipelines reported to PHMSA for the period of 1992 to 2011.
      Table 6  Reported Safety Incidents on Carbon Dioxide Pipelines 1992  -  2011

      Source:  PHMSA
      Thirty-four incidents were reported during the nearly twenty year period. This is significantly lower than the incidents reported for natural gas or petroleum product pipelines. For example, there were 3,009 incidents reported for hazardous liquid pipelines other than carbon dioxide during the period 2002 to 2009. No deaths or injuries were reported as a result of the reported incidents. The incidents resulted in the release of 126,000 barrels (5,292,000 gallons) of carbon dioxide and resulted in a little less than $1 million in damages. Most of the damages were for the loss of the carbon dioxide product and repair of the pipeline. Costs for remediation and cleanup were very low, indicating that little environmental damage occurred. Most of the incidents were either leaks or operation of a pressure relief valve, with one reported incident of a puncture caused by excavation. The most common causes of the incidents were failure of welds or of pipeline components such as valves, seals, and pumps. Malfunctioning relief valves were also implicated in several cases.
6.0 Future Projects
      An increase in the number and mileage of carbon dioxide pipelines is predicted for the future. The continued interest in using carbon dioxide to boost oil recovery is leading to new proposed projects to bring carbon dioxide to oil fields. GS is also moving forward, with several new research projects moving forward and the first commercial scale facilities being planned. Future projects can be divided into two categories: (1) projects that are in the planning stages and have permit applications or other planning documents and (2) pipelines that may be associated with projects that have not been planned or are only in the conceptual stages. Those in the first category can be identified by searching public documents such as news releases, permit applications, and project reports. Those in the second category must necessarily be predicted using assumptions of the extent of pipelines needed and the projects that will be built. Table 7 shows a list of projects that have been proposed or are in the permitting stages. Following the table is a brief description of each project.

   Table 7.  Proposed Carbon Dioxide Pipelines.
Project  -  Operator
Miles of Pipe
Source
Sink
Anticipated Completion Date
GreenCore - Denbury
232
Lost Cabin Natural Gas Plant, Medicine Bow Synfuel Plant, Riley Ridge Gas Plant
Bell Creek Oil Field,
2012
Midwest  -  Denbury
500  -  700
Gasification Plants in IN, IL, and KY
Gulf Coast Oil Fields
Uncertain
Hydrogen Energy California
4
Rio Tinto Hydrogen Plant, CA
Elk Hills Oil Field
2015
Chapparal
70
Coffeeville Fertilizer Plant
Existing EOR pipelines
2013
Cano Milnesand Pipeline
40
Cortez CO2 Pipeline
Milnesand and Chaveroo Oil Fields
2015
Conestoga Pipeline
15
Garden City, KS ethanol plant
Stuart Oil Field
2011
Archer Daniels Midland CCS project #1
1.2
Decatur, IL ethanol plant
Mt. Simon Saline Aquifer
2013
Taylorville Energy Center
4.75
Taylorville Energy Center
Mt. Simon Saline Aquifer
2013
FutureGen
32
FutureGen Power Plant
Mt. Simon Saline Aquifer
2015
Kevin Dome
6
Kevin Dome
Duperow Formation
2013
Williston Basin
150
Antelope Valley Power Plant
Williston Basin Oil Field
2013
Virginia City Hybrid Energy Center
25
Virginia City Hybrid Energy Center Power Plant
Coal Seams and Saline Aquifers
2015
St. John's Pipeline
200  -  400
St. John's Dome, Cottonwood Canyon Dome
Denver City Hub or McElmo Pipeline
2016
Mesaba Energy Project
265  -  610
Mesaba Energy Plant
Sequestration Site or Oil Fields
2014
Kimberlina Project
5 -10
Kimberlina Power Plant
Oil Fields
2015
Mountaineer Project
12  -  26
Mountaineer Power Plant
Mt. Simon Aquifer
Cancelled
Future Gen 1
1  -  59
Power Plant
Aquifer
Unknown
C-6 Resources
Unknown
Local Industrial Sources
Aquifer
Cancelled

   Denbury's Greencore Line: Denbury has started construction on this project. The first phase involves 232 miles of pipeline from the Lost Cabin Gas plant in Colorado to the Bell Creek Oil Field. That phase of the project is expected to be completed in December, 2012. Denbury eventually plans on expanding the pipeline to take carbon dioxide from a coal to liquids plant run by DKRW near Medicine Bow, MT and a gas plant near Riley Ridge, WY. The Medicine Bow plant is expected to come on line in 2014. A date was not mentioned for the hook up with Riley Ridge. The line will also likely extend to other oil fields that Denbury is looking to acquire in Wyoming (Fugleburg, 2011).
   Denbury's Midwest Line: Denbury has proposed building a carbon dioxide pipeline from several coal gasification plants in the Midwest. Denbury has proposed two routes -- either east through Kentucky and Tennessee to Mississippi or west through Missouri and Arkansas into Louisiana. The pipeline would connect with Denbury existing pipelines from Jackson Dome. The pipeline would be 500 to 700 miles in length depending on the route chosen. Four gasification plants have tentative agreements with Denbury to supply carbon dioxide: Rockport, IN; Taylorville, IL; Cash Creek, KY; and Edwardsport, IN. Only the Edwardsport facility has begun construction and the other three gasification plants are awaiting funding or permit approval. Therefore, this pipeline is tentative and it is difficult to predict when and if it will be constructed (Lydersen, 2012).
   Hydrogen Energy of California: This facility is in the planning process. It plans to take carbon dioxide produced from a hydrogen plant owned by BP and Rio Tinto. It will use a 4 mile long pipeline to transport the carbon dioxide produced to the Elk Hills Oil Field outside of Bakersfield, CA. The plan is to sequester the carbon dioxide while performing enhanced oil recovery. The project is expected to be complete in 2015 (Hydrogen Energy California, 2009).
   Chapparral Energy Pipeline: Chapparral Energy is planning on building a carbon dioxide pipeline that will tie in their existing carbon dioxide pipelines and add a source from the Coffeyville fertilizer plant. The pipeline would extend from the Coffeeville plant in southeastern Kansas to existing lines from the Koch fertilizer plant in Oklahoma, the Arkalon ethanol plant in Kansas, and the Agrium Fertilizer plant in Texas. It would extend to oil fields in the panhandle of Oklahoma, some of which are currently supplied by carbon dioxide from the Permian basin hub. The initial phase will include 70 miles of pipe to the North Burbank unit in northeastern Oklahoma. That phase is expected to be complete in 2013. The pipeline to connect all the projects together is scheduled for a later, unknown date (Chapparal Energy, 2011).
   Conestoga Energy Partners Pipeline: Conestoga Energy Partners is constructing a pipeline to bring carbon dioxide from a Garden City, Kansas ethanol plant to the Stuart Oil Field in Kansas. The project will involve a little less than 15 miles of pipeline and was expected to be operational in 2011 (Global CCS Institute, 2010).
   Cano Pipeline: Cano has entered an agreement to take carbon dioxide from the Cortez pipeline for use in its Chaveroo and Milnesand oil fields. The pipeline will be 40 miles long and 8 inches in diameter. Completion is expected in 2015 (Investorhub, 2012).
   Archer Daniels Midland (ADM) Projects: ADM is planning two carbon sequestration projects that will take carbon dioxide from their Decatur, IL ethanol plant and inject it into the Mt. Simon saline aquifer. The UIC permitting process is currently underway and injection is anticipated to begin sometime in 2013. The project will involve a 6,400 foot, 6 inch pipeline from the plant to the injection wells. It is a demonstration project and is planned to operate for three years. Its planned use may be extended if initial tests are successful (ADM, 2012).
   Taylorville Energy Center: The Taylorville Energy Center is a proposed IGCC plant that is proposing to inject carbon dioxide into the Mt. Simon aquifer in Illinois for carbon sequestration. The project includes 4.75 miles of pipe from the plant to 3 or 4 injection wells. The main pipe will be 16 inches in diameter, with 12 inch pipes leading to the wells. The project is currently in the permitting process and will likely begin operation with one well in the next year or two (TEC, 2012).
   FutureGen 2.0: The FutureGen project will retrofit an existing coal burning power plant in Meredosia, IL with oxycombustion technology. Carbon dioxide will be captured from the plant and stored in a sequestration site in the Mt. Simon Formation. The project will require a 32 mile pipeline and is expected to be completed in 2015 (Lee, 2011).
   Kevin Dome: The Big Sky Regional Carbon Sequestration Partnership is planning a sequestration study project in the Kevin Dome in Montana. The project will involve 6 miles of 2 inch pipeline from the source in the Kevin Dome to the sequestration site. The project is currently scheduled to begin injection in late 2013 (BSCSRP, 2012).
   Williston Basin: The Williston Basin project is a DOE sponsored sequestration project. It has already been through its preliminary test injections. The final project includes a 150 mile pipeline from the Antelope Valley Power Plant in North Dakota to the Williston Basin oil fields (NETL, 2008).
   Virginia City Hybrid Energy Center: This project is a carbon sequestration demonstration project. It will involve up to 25 miles of pipeline from Dominion Power's Virginia City Hybrid Energy Center to coal seams and saline aquifers in southwest Virginia. It is planned for completion in 2015 (McGee, 2005).
   St. John's Pipeline: The St. John's pipeline is a proposed project by Kinder Morgan. It is designed to take carbon dioxide from its newly acquired natural carbon dioxide sources in the St. John's unit and Cottonwood Canyon unit and transport it to Kinder Morgan's network in Texas. Testing of wells is currently being conducted. Depending on the production obtained from the carbon dioxide injection wells, either a 400 mile, 20 inch pipeline will be constructed directly to Kinder Morgan's Denver City hub or a 200 mile, 10 inch pipeline will be constructed to tie-in to the McElmo Dome pipeline (Arizona Geology, 2012).
   Mesaba Energy Project: The Mesaba Energy Project is a planned energy plant in Minnesota. As part of the plan, several options for sequestration were proposed. Options ranged from a 265 mile pipeline to a local saline aquifer sequestration site, to a three phase pipeline to oil fields in North Dakota and Canada. The project was originally scheduled for completion in 2014 but its current schedule is unknown (DOE, 2007).
   Kimberlina Project: The Kimberlina Power Plant is a planning to sequester carbon dioxide initially on-site as a research project. After approximately 4 years they anticipate building a 5 to 10 mile pipeline to local oil fields outside of Bakersfield, California. The original schedule was for enhanced oil recovery to begin in 2015. It is not known if the project is on schedule (Clean Energy Systems, 2012).
   Mountaineer Project: The Mountaineer project planned to inject 90 percent of the output of the Mountaineer Power Plant in West Virginia into the Mount Simon Aquifer at an injection site about 12 miles from the plant. A total of up to 26 miles of pipeline was planned. After an initial test phase the project was cancelled because of unfavorable economics (DOE, 2011).
   Future Gen 1 Project: The FutureGen project proposed to build a new IGCC power plant that would inject all of its flue gas into a saline aquifer. Initial evaluation was done for 5 sites that required between 1 and 59 miles of pipeline (DOE, 2006). This initial phase was cancelled.
   C-6 Resources: The project had planned to pipe carbon dioxide from various industrial sources in the San Francisco Bay area to a sandstone aquifer in Solano County. Exact pipeline routes had not been planned. The project received initial funding from DOE for some pilot tests but the project was cancelled before any pipelines were planned or constructed (CIEE, 2010)
   It should be noted that all of the above projects are planned, but not yet constructed. Some have been cancelled and others may not be completed. The above list, however, provides a reasonable estimate of the magnitude and types of projects that can be expected over the next five years.
   Predicting future carbon dioxide pipeline production beyond 2015 involves making some assumptions and predictions regarding the number of projects planned for the future. Sequestration projects are not likely to be financially attractive absent carbon dioxide legislation or some other financial incentives. If such incentives were lacking, future carbon dioxide would likely be limited to a few federally funded projects along with enhanced oil recovery projects. Oil recovery projects will likely continue to grow, as there is economic incentive without the additional benefit of carbon sequestration. The increase in pipelines to oil fields will depend to some extent on oil prices but is more likely to proceed without federal funding or legislation. As Figure 3 demonstrates, carbon dioxide pipelines have been built at a rate of 500 to 1,000 miles a decade after the initial boom in the 1980s. Since the increase in 2010 alone is already several hundred miles, it would appear that pace might be picking up again. Table 7 suggests that between 1,500 and 2,000 miles of pipeline could be built in the next 5 years. Even without large regulatory incentives, based on the above planned projects, it is possible that as much as 6,000 to 8,000 miles of carbon dioxide pipeline could be constructed in the next 20 years.
   If a large impetus for carbon sequestration develops, a larger network of carbon dioxide pipelines will be built. While there have been several modeling exercises to predict federal or state level pipeline networks connecting multiple sources to multiple sequestration sites, it seems like such an extensive network would likely be in the more distant future. IEA has predicted about 17 sequestration projects by 2020 with much more significant growth to 250 projects by 2050. An IOGCC report predicted that about 77 percent of sequestration projects could store carbon dioxide on the same site as it is captured. An additional 11 percent could store the carbon dioxide within 100 miles (IOGCC, 2010). Therefore, large sequestration pipeline networks may not be needed and, if they are, would likely be built over in the longer-term. If such a network became necessary, several studies have estimated the miles of pipeline that would be required to meet national carbon emission goals. An Interstate National Gas Association of America study found that a network of between 5,900 miles and 36,050 miles would be required to sequester carbon dioxide in the United States by 2030. The lower number presumes a 15 percent reduction in carbon dioxide emissions and low use of carbon dioxide for enhanced oil recovery. The higher figure assumes a 50 percent reduction in carbon dioxide emissions and a high use of carbon dioxide for enhanced oil recovery (INGAA, 2009). A Pacific Northwest National Laboratory Study estimated 11,000 miles of pipeline would be needed by 2050 to reach a goal of limiting atmospheric carbon dioxide concentrations to 550 ppm, and 23,000 miles would be needed to meet a goal of limiting atmospheric carbon dioxide to  450 ppm (Dooley et al., 2009). Given the currently planned projects, the high end of these figures seems unlikely in the next 20 years; however, the lower end of these figures might represent a more reasonable estimate for carbon dioxide pipelines in the next 20 years.

   References
ADM. 2012. Archer Daniels Midland Permit Application.

Arizona Geology. 2012. Accessed at: http://arizonageology.blogspot.com/2012/04/kinder-morgan-outlines-plans-for-major.html

Barrie, J., K. Brown, P.R. Hatcher, and H.U. Schellhase. 2004. Carbon Dioxide Pipelines: A Preliminary Review of Design and Risks. Presented at GHGT 2004.

Bergman, P.P., and E.M. Winter. 1997. Disposal of Power Plant CO2 in Depleted Oil and Gas Reservoirs in Texas. Energy Conversion and Management. V. 38 pp. S211  -  S216.

Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G. De La Torre, and D. Simbeck. 2003. Economic Evaluation of CO2 Storage and Sink Enhancement Options.

BSRCSP. 2012. Accesses at: http://www.bigskyco2.org/research/geologic/kevinstorage

Carbon Sequestration Leadership Forum. Undated. CO2 Transportation: Is it Safe and Reliable? http://www.cslforum.org/publications/documents/CSLF_inFocus_CO2Transportation.pdf

Carr, T.R., and M.K. Dubois. 2007. Results of Integrated Biofuels and Value Added Sequestration Project in Russel, KS. Presented at the 6[th] Annual Conference on Carbon Capture and Sequestration.

CIEE. 2010. Background Reports for the California Carbon Capture and Storage Review Panel.
California Institute for Energy and Environment.

Clean Energy Systems. 2012. Accessed at http://www.cleanenergysystems.com/faq.html#17

Cosham, A., and R. Eiber. 2007. Fracture Control in Carbon Dioxide Pipelines. Journal of Pipeline Engineering. 3[rd] quarter. p. 147

Chapparal Energy. 2011. Wells Fargo Energy Conference. Available at http://www.chaparralenergy.com/pressreleases/Wells%20Fargo%20Energy%20Conference_To%20print%20for%208K%20and%201x1.pdf

DOE. 2006. Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement.

DOE. 2007. Mesaba Energy Project, Draft EIS.

DOE. 2011. Mountaineer Commercial Scale Carbon Capture and Storage Project: Draft Environmental Impact Statement Summary.

Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2009. Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks. Energy Procedia 1. Pp. 1595-1602.

EPA. 2011. Assessment of the Potential Costs, Benefits, and Other Impact of the Conditional Exclusion from the RCRA Definition of Hazardous Waste for CO2 Streams Managed in UIC Class VI Wells for the Purposes of Geologic Sequestration

FERC. 2006. 115 FERC 962,266

Fredet, A., S. Saysset, P. Odru, P. Broudin, J. Ruer, and M. Bonnisel. 2007. Technical and Economic Assessement of CO2 Transportation for CCS Purposes.

Fugleburg, J. 2011. Construction of Carbon Dioxide Pipeline Starts this Year. Wyoming Star-Tribune May 26, 2011.

Global CCS Institute. 2010. Global Status of BECCS Projects 2010.

Hydrogen Energy California. 2009. Revised Application for Certification for Hydrogen Energy California.

INGAA. 2009. Carbon Sequestration and Storage: Developing a Transportation Infrastructure.

IOGCC. 2010. A Policy, Legal, and Regulatory Evaluation of the Feasibility of a National Pipeline Infrastructure for the Transport and Storage of Carbon Dioxide.

Investorhub. 2012. Available at http://investorshub.advfn.com/boards/read_msg.aspx?message_id=72260578

Lee, D.S.W., 2011. FutureGen "Clean Coal" Project Still has Hurdles to Clear. McDonough Voice.com April 6, 2011.

Lydersen, K. 2012. With no sources of CO2, Midwest pipeline project in limbo. Midwest Energy News, April 26, 2012.

Marston Law. 2012. http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm accessed on 5/16/2012

McGee, D. 2009. Tech, Dominion Propose Carbon-Capture Project. Richmond Times Dispatch, August 26, 2009.

MIT. 2007.  The Future of Coal: Options for a Carbon Constrained World.

NETL. 2008. Plains CO2 Reduction Partnership, Williston Basin Demonstration Test Fact Sheet. Accessed at http://www.netl.doe.gov/publications/proceedings/08/rcsp/factsheets/20-PCOR_Williston%20Basin%20Demo%20Test_PhIII_and_EOR_Demo.pdf

Oil and Gas Journal. 2010. Exxon Mobil Finishes Shute Creek Carbon Capture Expansion.

Pew Charitable Trust. 2008. The Role of CO2 Enhanced Oil Recovery in Ohio's Economy and Energy Future.

Radevsky, R., and D. Scott. 2004. Pipeline Insurance: Technical Aspects of Underwriting and Claims. Presented at the Conference on Terrain and Geohazard Challenges Facing Onshore Oil and Gas.

Rubin, E.S., M.B. Berkenpas, and S.T. McCoy. 2008. Technical Documentation:  The Economics of CO2 Transport by Pipeline Storage in Saline Aquifers and Oil Reserves. Carnegie Mellon University.

Seevam, P., J.M. Race, and M.J. Downie. 2007. Carbon Dioxide Pipelines for Sequestration in the UK: an Engineering Gap Analysis. Journal of Pipeline Engineering 2007, 3[rd] quarter. pp. 133-146.

TEC. 2012. Taylorville Energy Center UIC Permit Application.

Tetra Tech. 2009. Assessment of Risk, Legal Issues, and Insurance for Geologic Carbon Sequestration in Pennsylvania. Pennsylvania Department of Conservation and Natural Resources.

Texas RRC. 2012. Texas RRC T-4 Permits viewed at: https://rrcsearch3.neubus.com/esd3-rrc/index.php?_module_=esd&_action_=keysearch&profile=12

   Appendix A
   Standards Incorporated by Reference into Federal Pipeline Regulations

   AGA Pipeline Research Committee, Project PR-3-805, "A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe"
   ANSI/API Specification 5L/ISO 3183 "Specification for Line Pipe"
   API Recommended Practice 5L1, "Recommended Practice for Railroad Transportation of Line Pipe"
   API Recommended Practice 5LW, "Transportation of Line Pipe on Barges and Marine Vessels"
   ANSI/API Specification 6D "Specification for Pipeline Valves
   API Specification 12F "Specification for Shop Welded Tanks for Storage of Production Liquids"
   API 510 "Pressure Vessel Inspection Code: In-Service Maintenance Inspection, Rating, Repair, and Alteration"
   API Standard 620 "Design and Construction of Large, Welded, Low-Pressure Storage Tanks"
   API Standard 650 "Welded Steel Tanks for Oil Storage"
   ANSI/API Recommended Practice 651 "Cathodic Protection of Aboveground Petroleum Storage Tanks"
   ANSI/API Recommended Practice 652 "Lining of Aboveground Petroleum Storage Tank Bottoms"
   API Standard 653 "Tank Inspection, Repair, Alteration, and Reconstruction"
   API Standard 1104 "Welding of Pipelines and Related Facilities'
   API Recommended Practice 1130, "Computational Pipeline Monitoring for Liquids: Pipeline Segment"
   API Recommended Practice 1162, "Public Awareness Programs for Pipeline Operators"
   API Recommended Practice 1165, "Recommended Practice for Pipeline SCADA Displays,"

   API Standard 2000 "Venting Atmospheric and Low-Pressure Storage Tanks"
   API Recommended Practice 2003 "Protection Against Ignitions Arising out of Static, Lightning, and Stray Currents"
   API Publication 2026 "Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service"
   API Recommended Practice 2350 "Overfill Protection for Storage Tanks in Petroleum Facilities"
   API Standard 2510 "Design and Construction of LPG Installations"
   API Recommended Practice 1162 "Public Awareness Programs for Pipeline Operators,"
   API Recommended Practice 1168 "Pipeline Control Room Management,"
   ASME/ANSI B16.9-20073 (February 2004) "Factory-Made Wrought Steel Buttwelding Fittings"
   ASME/ANSI B31.4-20062 (October 2002) "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids"
   ASME/ANSI B31G-1991 (Reaffirmed; 2004) "Manual for Determining the Remaining Strength of Corroded Pipelines"
   ASME/ANSI B31.8-20073 (February 2004) "Gas Transmission and Distribution Piping Systems"
   ASME Boiler and Pressure vessel Code, Section VIII, Division 1 "Rules for Construction of Pressure Vessels,"
   ASME Boiler and Pressure Vessel Code, Section VIII, Division 2 "Alternate Rules for Construction of Pressure Vessels"
   ASME Boiler and Pressure vessel Code, Section IX "Welding and Brazing Qualifications,"
   MSS SP-75-2004 "Specification for High Test Wrought Butt Welding Fittings"
   ASTM Designation: A53/A53M-07,04a (2004) "Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless"
   ASTM Designation: A106/A106M-08,04b (2004) "Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service"
   ASTM Designation: A 333/A 333M-05, "Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service"
   ASTM Designation: A 381-96 (Reapproved 20051), "Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems"

   ASTM Designation: A 671-06,04 (2004) "Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures"
   ASTM Designation: A 672-0896 (Reapproved 2001) "Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures"
   ASTM Designation: A 691-98 (Reapproved 20072), "Standard Specification for Carbon and Alloy Steel Pipe Electric-Fusion-Welded for High-Pressure Service at High Temperatures"
   NFPA 30(2003) "Flammable and Combustible Liquids Code"
   NACE SP0169-2007, Standard Practice, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems"
   NACE SP0502-2008, Standard Practice, "Pipeline External Corrosion Direct Assessment Methodology"


[Federal Register Volume 81, Number 76 (Wednesday, April 20, 2016)]
[Notices]
[Pages 23311-23313]
[FR Doc No: 2016-09150]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2011-N-0655]

Animal Generic Drug User Fee Act; Public Meeting; Request for
Comments

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice of public meeting; request for comments.

-----------------------------------------------------------------------

SUMMARY: The Food and Drug Administration (FDA) is announcing a public
meeting on the Animal Generic Drug User Fee Act (AGDUFA). FDA invites
public comment on the AGDUFA program and suggestions regarding the
features FDA should propose for the next AGDUFA program.

DATES: The meeting will be held on May 16, 2016, from 1 p.m. to 4 p.m.
In order to be taken into consideration before the public meeting,
submit either electronic or written comments to the docket by May 4,
2016. To permit the widest possible opportunity to obtain comments on
all aspects of the public meeting, the docket will remain open for
comment through December 1, 2017. In addition to being publicly
viewable at http://www.regulations.gov, comments received by June 16,
2016, suggesting changes to the program, will also be published on
http://www.fda.gov/ForIndustry/UserFees/AnimalGenericDrugUserFeeActAGDUFA/ucm270232.htm. See the SUPPLEMENTARY
INFORMATION section for registration date and information.

ADDRESSES: The meeting will be held at the Food and Drug
Administration, 7519 Standish Pl., 3rd floor, Rm. A, Rockville, MD
20855.
    You may submit comments as follows:

Electronic Submissions

    Submit electronic comments in the following way:
     Federal eRulemaking Portal: http://www.regulations.gov.
Follow the instructions for submitting comments. Comments submitted
electronically, including attachments, to http://www.regulations.gov
will be posted to the docket unchanged. Because your comment will be
made public, you are solely responsible for ensuring that your comment
does not include any confidential information that you or a third party
may not wish to be posted, such as medical information, your or anyone
else's Social Security number, or confidential business information,
such as a manufacturing process. Please note that if you include your
name, contact information, or other information that identifies you in
the body of your comments, that information will be posted on http://www.regulations.gov.
     If you want to submit a comment with confidential
information that you do not wish to be made available to the public,
submit the comment as a written/paper submission and in the manner
detailed (see ``Written/Paper Submissions'' and ``Instructions'').

Written/Paper Submissions

    Submit written/paper submissions as follows:
     Mail/Hand delivery/Courier (for written/paper
submissions): Division of Dockets Management (HFA-305), Food and Drug
Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
     For written/paper comments submitted to the Division of
Dockets Management, FDA will post your comment, as well as any
attachments, except for information submitted, marked and identified,
as confidential, if submitted as detailed in ``Instructions.''
    Instructions: All submissions received must include the Docket No.
FDA-2011-N-0655 for ``Animal Generic Drug User Fee Act; Public Meeting;
Request for Comments.'' Received comments will be placed in the docket
and, except for those submitted as ``Confidential Submissions,''
publicly viewable at http://www.regulations.gov or at the Division of
Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
     Confidential Submissions--To submit a comment with
confidential information that you do not wish to be made publicly
available, submit your comments only as a written/paper submission. You
should submit two copies total. One copy will include the information
you claim to be confidential with a heading or cover note that states
``THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.'' The Agency will
review this copy, including the claimed confidential information, in
its consideration of comments. The second copy, which will have the
claimed confidential information redacted/blacked out, will be
available for public viewing and posted on http://www.regulations.gov.
Submit both copies to the Division of Dockets Management. If you do not
wish your name and contact information to be made publicly available,
you can provide this information on the cover sheet and not in the body
of your comments and you must identify this information as
``confidential.'' Any information marked as ``confidential'' will not
be disclosed except in accordance with 21 CFR 10.20 and other
applicable disclosure law. For more information about FDA's posting of
comments to public dockets, see 80 FR 56469, September 18, 2015, or
access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm.
    Docket: For access to the docket to read background documents or
the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in
the heading of this document, into the ``Search'' box and follow the
prompts and/or go to the Division of Dockets Management, 5630 Fishers
Lane, Rm. 1061, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT: Cassie Ravo, Center for Veterinary
Medicine, Food and Drug Administration, 7519 Standish Pl., Rockville,
MD 20855,<PHONE_NUMBER>, FAX:<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Introduction

    The authority for AGDUFA expires September 30, 2018. Without new
legislation, FDA will no longer have the authority to collect user fees
to fund the generic new animal drug review process. Prior to beginning
negotiations with the regulated industry on AGDUFA reauthorization,
section 740A(d)(2) of the Federal Food, Drug, and Cosmetic Act (the
FD&C Act) (21 U.S.C. 379j-13(d)(2)) requires FDA to: (1) Publish a
notice in the Federal Register requesting public input on the
reauthorization; (2) hold a public meeting at which the public may
present its views on the reauthorization including specific suggestions
for changes to the goals referred in section 740A(a) of FD&C Act; (3)
provide a period of 30 days after the public meeting to obtain written
comments from the public suggesting changes; and (4) publish the
comments on FDA's Web site. FDA is holding a public meeting to gather
information on what FDA should consider including in the
reauthorization of AGDUFA. FDA is interested in responses from the
public on the following two general questions and welcomes other
pertinent information that stakeholders would like to share:
    1. What is your assessment of the overall performance of the AGDUFA
program thus far?
    2. What aspects of AGDUFA should be retained, changed, or
discontinued to further strengthen and improve the program?
    The following information is provided to help potential meeting
participants better understand the history and evolution of AGDUFA and
its current status.

II. Background

    The Animal Generic Drug User Fee Act enacted in 2008 (Pub. L. 110-
316; hereinafter referred to as ``AGDUFA I'') amended the FD&C Act to
authorize FDA's first ever generic new animal drug user fee program.
AGDUFA I provided FDA with additional funds to enhance the performance
of the generic new animal drug review process. Furthermore, the
authorization of AGDUFA I enabled FDA's continued assurance that
generic new animal drug products are safe and effective, and enabled
FDA's continued support for lower-cost alternatives to brand drugs for
consumers. Under AGDUFA I, FDA agreed to meet review performance goals
for certain submissions over 5 years from fiscal year (FY) 2009 through
FY 2013. These review performance goals strive to expedite the review
of abbreviated new animal drug applications (ANADAs) and reactivations,
supplemental ANADAs, and generic investigational new animal drug
(JINAD) submissions.
    Under AGDUFA I, the industry agreed to pay user fees that are
available to FDA, in addition to appropriated funds, to spend on the
generic new animal drug review process. Moreover, FDA's authority to
collect user fees is contingent on a certain level of spending from
appropriated funds, as adjusted for inflation.
    AGDUFA I established increasingly stringent review performance
goals over a 5-year period from FY 2009 through FY 2013. By the 5th and
final year of AGDUFA I, FDA agreed to review and act on 90 percent of
the following submission types within the specified timeframes:
     Original ANADAs and reactivations within 270 days of the
submission date.
     Administrative ANADAs (ANADAs submitted after all
scientific decisions have been made during the JINAD process, i.e.,
prior to the submission of the original ANADAs) within 100 days after
the submission date.
     Manufacturing supplemental ANADAs and reactivations within
270 days after the submission date.
     JINAD study submissions within 270 days after the
submission date.
     JINAD protocol submissions within 100 days after
submission date. JINAD protocol submissions consist of protocols
without substantial data that FDA and the sponsor consider to be an
essential part of the basis to make the decision to approve or not
approve an ANADA or supplemental ANADA.
    The additional resources provided under AGDUFA I enabled FDA to
completely eliminate the backlog of ANADA and JINAD submissions by
August 2010.
    In 2013, before AGDUFA I expired, Congress passed the Animal
Generic Drug User Fee Amendments of 2013 (Pub. L. 113-14; hereinafter
referred to as ``AGDUFA II'') which included an extension of AGDUFA for
an additional 5 years (FY 2014 to FY 2018). AGDUFA II is maintaining
the AGDUFA I performance goals regarding work queue procedures, timely
meetings with industry, review of administrative ANADAs, review of
protocols without substantial data, and amending similar applications
and submissions. In addition, FDA agreed to the following program
enhancements to further improve review processes:
     Developing a shortened review time process for certain
ANADA and JINAD submissions.
     Permitting certain prior approval manufacturing
supplements to be resubmitted as ``Supplement-Changes Being Effected in
30 days.''
     Developing guidance for a two-phased Chemistry
Manufacturing and Controls technical section submission and review
process under the JINAD file.
     Permitting comparability protocols to be submitted as
protocols without substantial data in a JINAD file.
     Improving timeliness and predictability of foreign pre-
approval inspections.
     Developing and implementing a question-based review
process for the bioequivalence submissions.
    FDA has published a number of reports that provide useful
background on AGDUFA I and AGDUFA II. AGDUFA-related Federal Register
notices, guidances, legislation, performance reports, and financial
reports and plans can be found at: http://www.fda.gov/ForIndustry/UserFees/AnimalGenericDrugUserFeeActAGDUFA/default.htm.

III. Meeting Information

A. Meeting Format

    In general, the meeting format will include presentations by FDA
followed by an open public comment period. Registered speakers for the
open public comments will be grouped and scheduled in advance of the
meeting based on their affiliation (scientific and academic experts/
veterinary professionals, representatives of consumer advocacy groups,
and the regulated industry) and timing of their registration. FDA
presentations are planned from 1 p.m. until 2 p.m. The open public
comment portion of the meeting for registered and scheduled speakers is
planned to begin at 2 p.m. An opportunity for additional open public
comments from meeting attendees will commence following the registered
presentations, if time permits.
    FDA policy issues are beyond the scope of these reauthorization
discussions. Accordingly, the presentations should focus on process
enhancements and funding issues, not on policy issues.

B. Meeting Questions

    Please consider the following questions for this meeting:
    1. What is your assessment of the overall performance of the AGDUFA
program thus far?
    2. What aspects of AGDUFA should be retained, changed, or
discontinued to further strengthen and improve the program?

C. Registration

    If you wish to attend and/or present at the meeting, please
register by email to<EMAIL_ADDRESS>by May 4, 2016. Your email
should contain complete contact information for each attendee,
including name, title, affiliation, address, email, and telephone
number. Also, please self-identify as a member of one of the following
stakeholder categories: Scientific or academic experts; veterinary
professionals; patients and consumer advocacy groups; or the regulated
industry and whether you are requesting a scheduled presentation.
Registration is free and available on a first-come, first-served basis.
Early registration is recommended since seating is limited. FDA may
limit the number of participants from each organization based on space
constraints. Registrants will receive confirmation once their
registrations are accepted. Onsite registration on the day of the
public meeting will be based on space availability. FDA will try to
accommodate all persons who wish to make a presentation. The time
allotted for presentations may depend on the number of persons who wish
to speak.
    If you need special accommodations due to a disability, please
contact Cassie Ravo (see FOR FURTHER INFORMATION CONTACT) at least 7
days before the meeting.

D. Transcripts

    Please be advised that as soon as the transcript is available, it
will be accessible at http://www.fda.gov/ForIndustry/UserFees/AnimalGenericDrugUserFeeActAGDUFA/ucm270232.htm. It may be viewed at
the Division of Dockets Management (see ADDRESSES). A transcript will
also be made available in either hard copy or on CD-ROM, after
submission of a Freedom of Information request. The Freedom of
Information office address is available on the Agency's Web site at
http://www.fda.gov.

    Dated: April 12, 2016.
Leslie Kux,
Associate Commissioner for Policy.
[FR Doc. 2016-09150 Filed 4-19-16; 8:45 am]
 BILLING CODE 4164-01-P


[Federal Register Volume 79, Number 112 (Wednesday, June 11, 2014)]
[Notices]
[Page 33546]
[FR Doc No: 2014-13521]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. TS14-3-000]

Essential Power Rock Springs, LLC, Essential Power Operating
Company, LLC; Notice of Filing

    Take notice that on June 4, 2014, pursuant to section 358.1(d) \1\
of the Federal Energy Regulatory Commission's (Commission) Rules of
Practice and Procedure and Order Nos. 889,\2\ 2004,\3\ and 717,\4\
Essential Power Rock Springs, LLC, on behalf of itself and its
affiliate Essential Power Operating Company, LLC, filed a request for
waiver from the standards of conduct set forth in Part 358 of the
Commission's Regulations.
---------------------------------------------------------------------------

    \1\ 18 CFR 358.1(d) (2013).
    \2\ Open Access Same-Time Information System and Standards of
Conduct, Order No. 889, FERC Stats. & Regs. ] 31,035 (1996), order
on reh'g, Order No. 889-A, FERC Stats. & Regs. ] 31,049, order on
reh'g, Order No. 889-B, 81 FERC ] 61,253 (1997).
    \3\ Standards of Conduct for Transmission Providers, Order No.
2004, FERC Stats. & Regs. ] 31,155 at PP 17-20 (2003), order on
reh'g, Order No. 2004-A, FERC Stats. & Regs. ] 31,161, order on
reh'g, Order No. 2004-B, FERC Stats. & Regs. ] 31,166, order on
reh'g, Order No. 2004-C, FERC Stats. & Regs. ] 31,172 (2004), order
on reh'g, Order No. 2004-D, 110 FERC ] 61,320 (2005).
    \4\ Standards of Conduct for Transmission Providers, Order No.
717, FERC Stats. & Regs. ] 31,280 (2008), order on reh'g, Order No.
717-A, 129 FERC ] 61,043, order on reh'g, Order No. 717-B, 129 FERC
] 61,123, order on reh'g, Order No. 717-C, 131 FERC ] 61,045 (2010),
order on reh'g, Order No. 717-D, 135 FERC ] 61,017 (2011).
---------------------------------------------------------------------------

    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211, 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date. On or
before the comment date, it is not necessary to serve motions to
intervene or protests on persons other than the Applicant.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 5 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street NE., Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the
``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive email
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please email
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5:00 p.m. Eastern Time on July 7, 2014.

    Dated: June 4, 2014.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2014-13521 Filed 6-10-14; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 77, Number 89 (Tuesday, May 8, 2012)]
[Notices]
[Pages 27104-27105]
[FR Doc No: 2012-11000]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-66903; File No. SR-NYSEAmex-2012-27]

 Self-Regulatory Organizations; NYSE Amex LLC; Notice of Filing
and Immediate Effectiveness of Proposed Rule Change Implementing an
Increase to the Login Fee Within the NYSE Amex Options Fee Schedule

May 2, 2012.
    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
(``Act''),\1\ and Rule 19b-4 thereunder,\2\ notice is hereby given that
on April 27, 2012, NYSE Amex LLC (the ``Exchange'' or ``NYSE Amex'')
filed with the Securities and Exchange Commission (``Commission'') the
proposed rule change as described in Items I, II, and III below, which
Items have been prepared by the self-regulatory organization. The
Commission is publishing this notice to solicit comments on the
proposed rule change from interested persons.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
---------------------------------------------------------------------------

I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    The Exchange proposes to increase the login fee within the NYSE
Amex Options Fee Schedule (``Fee Schedule'') and to make this increase
operative on May 1, 2012. The text of the proposed rule change is
available at the Exchange, the Commission's Public Reference Room, and
www.nyse.com.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, the self-regulatory organization
included statements concerning the purpose of, and basis for, the
proposed rule change and discussed any comments it received on the
proposed rule change. The text of those statements may be examined at
the places specified in Item IV below. The Exchange has prepared
summaries, set forth in sections A, B, and C below, of the most
significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
    The Exchange is proposing to increase the login fee within the Fee
Schedule and to make this increase operative on May 1, 2012.
    The Exchange currently charges Floor brokers a $150 per month login
fee for access to the Floor broker Workstation (``FBW''), which is an
Exchange-sponsored Floor broker order entry system.\3\ In addition to
enabling Floor brokers to electronically submit orders to the Exchange,
the FBW contributes to Floor brokers complying with various Exchange
rules, such as the order format and system entry requirements of NYSE
Amex Options Rule 955NY.
---------------------------------------------------------------------------

    \3\ See Securities Exchange Act Release No. 59478 (February 27,
2009), 74 FR 9857 (March 6, 2009) (SR-NYSEALTR-2009-19).
---------------------------------------------------------------------------

    The Exchange proposes to increase the login fee from $150 per login
per month to $215 per login per month. This proposed increase, which
would be the first in the more than three years since the login fee was
implemented, would permit the Exchange to offset the increase in the
Exchange's cost to make the FBW available to Floor brokers and would
also permit the Exchange to continue to make enhancements and upgrades
to the FBW available to Floor brokers.
    The Exchange proposes that the increase to the login fee become
effective on May 1, 2012.
2. Statutory Basis
    The Exchange believes that the proposed rule change is consistent
with Section 6(b) of the Securities Exchange Act of 1934 (the
``Act''),\4\ in general, and furthers the objectives of Section 6(b)(4)
of the Act,\5\ in particular, because it provides for the equitable
allocation of reasonable dues, fees, and other charges among its
members, issuers and other persons using its facilities. Specifically,
the Exchange believes that the proposed rule change is reasonable,
equitable and not unfairly discriminatory because it would permit the
Exchange to offset the increase in the Exchange's cost to make the FBW
available to Floor brokers. The Exchange also believes that the
proposed rule change is reasonable, equitable and not unfairly
discriminatory because it would permit the Exchange to continue to make
enhancements and upgrades to the FBW available to Floor brokers.
Additionally, the Exchange believes that the proposed rule change is
reasonable, equitable and not unfairly discriminatory because the login
fee, and the proposed increase thereof, is applicable to all Floor
brokers that receive access to the FBW.
---------------------------------------------------------------------------

    \4\ 15 U.S.C. 78f(b).
    \5\ 15 U.S.C. 78f(b)(4).
---------------------------------------------------------------------------

B. Self-Regulatory Organization's Statement on Burden on Competition

    The Exchange does not believe that the proposed rule change will
impose any burden on competition that is not necessary or appropriate
in furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants, or Others

    No written comments were solicited or received with respect to the
proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    The foregoing rule change is effective upon filing pursuant to
Section 19(b)(3)(A) \6\ of the Act and subparagraph (f)(2) of Rule 19b-
4 \7\ thereunder, because it establishes a due, fee, or other charge
imposed by the NYSE Amex.
---------------------------------------------------------------------------

    \6\ 15 U.S.C. 78s(b)(3)(A).
    \7\ 17 CFR 240.19b-4(f)(2).
---------------------------------------------------------------------------

    At any time within 60 days of the filing of such proposed rule
change, the Commission summarily may temporarily suspend such rule
change if it appears to the Commission that such action is necessary or
appropriate in the public interest, for the protection of investors, or
otherwise in furtherance of the purposes of the Act.

IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml ); or
     Send an email to<EMAIL_ADDRESS>Please include
File Number SR-NYSEAmex-2012-27 on the subject line.

Paper Comments

     Send paper comments in triplicate to Elizabeth M. Murphy,
Secretary, Securities and Exchange Commission, 100 F Street NE.,
Washington, DC 20549-1090.

All submissions should refer to File Number SR-NYSEAmex-2012-27. This
file number should be included on the subject line if email is used. To
help the Commission process and review your comments more efficiently,
please use only one method. The Commission will post all comments on
the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml
). Copies of the submission, all subsequent amendments, all written
statements with respect to the proposed rule change that are filed with
the Commission, and all written communications relating to the proposed
rule change between the Commission and any person, other than those
that may be withheld from the public in accordance with the provisions
of 5 U.S.C. 552, will be available for Web site viewing and printing in
the Commission's Public Reference Room, 100 F Street NE., Washington,
DC 20549, on official business days between the hours of 10:00 a.m. and
3:00 p.m. Copies of such filing also will be available for inspection
and copying at the principal office of the Exchange. All comments
received will be posted without change; the Commission does not edit
personal identifying information from submissions. You should submit
only information that you wish to make available publicly. All
submissions should refer to File Number SR-NYSEAmex-2012-27 and should
be submitted on or before May 29, 2012.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\8\
---------------------------------------------------------------------------

    \8\ 17 CFR 200.30-3(a)(12).
---------------------------------------------------------------------------

Kevin M. O'Neill,
Deputy Secretary.
[FR Doc. 2012-11000 Filed 5-7-12; 8:45 am]
BILLING CODE 8011-01-P


[Federal Register Volume 82, Number 188 (Friday, September 29, 2017)]
[Notices]
[Page 45586]
[FR Doc No: C1-2017-20310]

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ENVIRONMENTAL PROTECTION AGENCY

[FRL-9968-18-OP]

EPA Smart Sectors Program Launch

Correction

    In Notice document 2017-20310, appearing on page 44783 in the issue
of Tuesday, September 26, 2017, make the following correction:
    On page 44783, in the second column, in the SUPPLEMENTARY
INFORMATION section, under ``General Information'', the first paragraph
should read as follows:
    EPA has initially identified the following sectors to work with:
Aerospace; agriculture; automotive; cement and concrete; chemical
manufacturing; construction; electronics and technology; forestry and
paper products; iron and steel; mining; oil and gas; ports and marine;
and utilities and power generation. Sectors were selected based on each
sector's potential to improve the environment and public health. EPA
welcomes participation from other stakeholders.

[FR Doc. C1-2017-20310 Filed 9-28-17; 8:45 am]
 BILLING CODE 1301-00-D


P-21-0085 Sanitized Support Documents Index:
 P-21-0085 Sanitized Premanufacture Notice (linked)
 P-21-0085 Sanitized Determination Document (linked)
 P-21-0085 Sanitized CHEM Report (attached)
 P-21-0085 Sanitized ECO Report (attached)
 P-21-0085 Sanitized ENG Report (attached)
 P-21-0085 Sanitized EXP Report (attached)
 P-21-0085 Sanitized Fate Report (attached)
 P-21-0085 Sanitized HLTH Report_POST-FOCUS FINAL (attached)


[Federal Register Volume 88, Number 40 (Wednesday, March 1, 2023)]
[Notices]
[Pages 12943-12944]
[FR Doc No: 2023-04206]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2023-N-0487]

Discussion Paper: Artificial Intelligence in Drug Manufacturing,
Notice; Request for Information and Comments

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice; establishment of a public docket; request for
information and comments.

-----------------------------------------------------------------------

SUMMARY: The Food and Drug Administration (FDA or Agency) is announcing
publication of a discussion paper providing information for
stakeholders and soliciting public comments on a specific area of
emerging and advanced manufacturing technologies. The discussion paper
presents areas for consideration and policy development identified by
the Center for Drug Evaluation and Research (CDER) scientific and
policy experts associated with application of artificial intelligence
(AI) to pharmaceutical manufacturing. The discussion paper includes a
series of questions to stimulate feedback from the public, including
CDER and the Center for Biologics Evaluation and Research (CBER)
stakeholders.

DATES: Submit either written or electronic comments and information by
May 1, 2023.

ADDRESSES: You may submit comments as follows. Please note that late,
untimely filed comments will not be considered. The https://www.regulations.gov electronic filing system will accept comments until
11:59 p.m. Eastern Time at the end of May 1, 2023. Comments received by
mail/hand delivery/courier (for written/paper submissions) will be
considered timely if they are received on or before that date.

Electronic Submissions

    Submit electronic comments in the following way:
     Federal eRulemaking Portal: https://www.regulations.gov.
Follow the instructions for submitting comments. Comments submitted
electronically, including attachments, to https://www.regulations.gov
will be posted to the docket unchanged. Because your comment will be
made public, you are solely responsible for ensuring that your comment
does not include any confidential information that you or a third party
may not wish to be posted, such as medical information, your or anyone
else's Social Security number, or confidential business information,
such as a manufacturing process. Please note that if you include your
name, contact information, or other information that identifies you in
the body of your

comments, that information will be posted on https://www.regulations.gov.
     If you want to submit a comment with confidential
information that you do not wish to be made available to the public,
submit the comment as a written/paper submission and in the manner
detailed (see ``Written/Paper Submissions'' and ``Instructions'').

Written/Paper Submissions

    Submit written/paper submissions as follows:
     Mail/Hand Delivery/Courier (for written/paper
submissions): Dockets Management Staff (HFA-305), Food and Drug
Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
     For written/paper comments submitted to the Dockets
Management Staff, FDA will post your comment, as well as any
attachments, except for information submitted, marked and identified,
as confidential, if submitted as detailed in ``Instructions.''
    Instructions: All submissions received must include the Docket No.
FDA-2023-N-0487 for ``Discussion Paper: Artificial Intelligence in Drug
Manufacturing, Notice; Request for Information and Comments.'' Received
comments, those filed in a timely manner (see ADDRESSES), will be
placed in the docket and, except for those submitted as ``Confidential
Submissions,'' publicly viewable at https://www.regulations.gov or at
the Dockets Management Staff between 9 a.m. and 4 p.m., Monday through
Friday,<PHONE_NUMBER>.
     Confidential Submissions: To submit a comment with
confidential information that you do not wish to be made publicly
available, submit your comments only as a written/paper submission. You
should submit two copies total. One copy will include the information
you claim to be confidential with a heading or cover note that states
``THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.'' The Agency will
review this copy, including the claimed confidential information, in
its consideration of comments. The second copy, which will have the
claimed confidential information redacted/blacked out, will be
available for public viewing and posted on https://www.regulations.gov.
Submit both copies to the Dockets Management Staff. If you do not wish
your name and contact information to be made publicly available, you
can provide this information on the cover sheet and not in the body of
your comments and you must identify this information as
``confidential.'' Any information marked as ``confidential'' will not
be disclosed except in accordance with 21 CFR 10.20 and other
applicable disclosure law. For more information about FDA's posting of
comments to public dockets, see 80 FR 56469, September 18, 2015, or
access the information at: https://www.govinfo.gov/content/pkg/FR-2015-09-18/pdf/2015-23389.pdf.
    Docket: For access to the docket to read background documents or
the electronic and written/paper comments received, go to https://www.regulations.gov and insert the docket number, found in brackets in
the heading of this document, into the ``Search'' box and follow the
prompts and/or go to the Dockets Management Staff, 5630 Fishers Lane,
Rm. 1061, Rockville, MD 20852,<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Elizabeth Giaquinto Friedman, Center
for Drug Evaluation and Research, Food and Drug Administration, 10903
New Hampshire Ave., Bldg. 51, Rm. 4162, Silver Spring, MD 20993, 240-
402-7930, [email protected].

SUPPLEMENTARY INFORMATION:

I. Background

    Advanced manufacturing is a term that describes an innovative
pharmaceutical manufacturing technology or approach that has the
potential to improve the reliability and robustness of the
manufacturing process and resilience of the supply chain. Advanced
manufacturing can: (1) integrate novel technological approaches, (2)
use established techniques in an innovative way, or (3) apply
production methods in a new domain where there are no defined best
practices. Advanced manufacturing can be used for new or currently
marketed large or small molecule drug products.
    FDA has recognized and embraced the potential of advanced
manufacturing. In 2014, CDER established the Emerging Technology
Program (ETP) to work collaboratively with companies to support the use
of advanced manufacturing. CDER observed a rapid emergence of advanced
manufacturing technologies through the ETP and recognized that
regulatory policies and programs may need to evolve to enable timely
technological adoption.
    The National Academies of Sciences, Engineering, and Medicine
issued a 2021 report titled Innovation in Pharmaceutical Manufacturing
on the Horizon: Technical Challenges, Regulatory Issues, and
Recommendations, highlighting innovations in integrated pharmaceutical
manufacturing processes. These innovations could have implications for
measurement, modeling, and control technologies used in pharmaceutical
manufacturing. AI may play a significant role in monitoring and
controlling advanced manufacturing processes.
    This discussion paper presents areas associated with the
application of AI to pharmaceutical manufacturing that FDA has
identified for consideration as FDA evaluates our existing risk-based
regulatory framework. CDER scientific and policy experts identified
these areas from a comprehensive analysis of existing regulatory
requirements applicable to the approval of drugs manufactured using AI
technologies. The areas of consideration in this discussion paper are
those for which FDA would like public feedback.
    There are additional areas of consideration not covered within this
document, for example, difficulties that could result from ambiguity on
how to apply existing regulations to AI or lack of Agency guidance or
experience. The areas of consideration presented in this discussion
paper focus on drug products that would be marketed under a new drug
application (NDA), abbreviated new drug application (ANDA), or biologic
license application (BLA). Public feedback will help inform CDER's
evaluation of our existing regulatory framework.
    While the initial analysis focused on products regulated by CDER,
FDA's CBER has also encountered a rapid emergence of advanced
manufacturing technologies associated with AI. As such, both CDER and
CBER stakeholders are invited to provide feedback on the discussion
questions.

II. Requested Information and Comments

    Interested persons are invited to provide detailed comments to CDER
and CBER on all aspects described in the discussion paper. To
facilitate input, FDA has developed a series of questions based on the
considerations articulated in the discussion paper. The questions are
not meant to be exhaustive, and FDA is also interested in any other
pertinent information stakeholders would like to share on this topic.
In all cases, FDA encourages stakeholders to provide the specific
rationale and basis for their comments, including any available
supporting data and information.

    Dated: February 24, 2023.
Lauren K. Roth,
Associate Commissioner for Policy.
[FR Doc. 2023-04206 Filed 2-28-23; 8:45 am]
BILLING CODE 4164-01-P