Page 1 U. S. A. CUN2003/ 052  FOREST SEEDLING NURSERIES FOREST TREE SEEDLINGS GROWN OUTDOORS AFTER BROADCAST FUMIGATIONS UNDER PLASTIC TARPS TABLE OF CONTENTS Introduction....................................................................................................................................................... 2 Critical Need for Methyl Bromide ..................................................................................................................... 2 Economic Impacts ............................................................................................................................................. 3 Response to Questions from MBTOC/ TEAP ..................................................................................................... 5 Definitions ...................................................................................................................................................... 11 References....................................................................................................................................................... 12 APPENDIX. Estimated Costs Of Converting A Loblolly Forest Tree Seedling Nursery From Soil Based To Containerized Soilless Culture1 ....................................................................................................................... 13 LIST OF TABLES Table 1. Region, Key Pests, and Critical Need for Methyl Bromide ................................................................... 3 Table 2. Measures of Economic Impact of Using Dazomet or Metam Sodium in Place of Methyl Bromide on Tree Seedling Nurseries in the U. S. a.......................................................................................................... 5 Table 3. Average Yearly Height Growth and Survival of Containerized and Bareroot Seedlings Planted During the Winter Period, November to Marcha .................................................................................................... 7 Table 4. Historical Use of Methyl Bromide in the Forest Seedling Sector* ....................................................... 8 Table 5. Calculation of the Nominated Amount of Methyl Bromide in the Forest Seedling Sector ..................... 8 D. Analysis of Net Costs: Converting 10 million Seedling Nursery from Bareroot to Containerized, Soilless Culture..................................................................................................................................................... 14 Page 2 INTRODUCTION The United States is providing the following additional information to clarify several issues for the forest seedling nursery CUE nomination. Millions of hectares of forestland, which are planted every year for reforestation, fiber production, and conservation uses, require efficient nurseries to provide seedlings. The large size of U. S. forests, many of which are publicly owned, also requires inexpensive production technologies to enable a vigorous, plentiful, and cost effective product. The use of methyl bromide ( MB) ( usually applied to a bed only once in three to four years) by forest seedling nurseries is an important means of reducing overall costs of seedling production that allows the 20 to 40 year investment in forests to be worthwhile. Additionally, the positive environmental value of reforestation was taken into consideration, even though it is not explicitly reflected in the economic analysis.

CRITICAL NEED FOR METHYL BROMIDE Forest seedling nurseries face numerous pests in the course of production, most importantly nutsedge weeds and certain fungal pathogens ( Table 1). While alternative technologies currently are being addressed by the industry, including investigating container production, in the near future MB is necessary for production requirements. Intensive seedling production relies on the ability of nursery managers to meet yield and quality goals, while minimizing production costs. Because of the importance of seedling quality ( due to the high correlation of quality and subsequent forest health and value), a failure to produce consistently healthy seedlings can have a devastating effect on the nurseries' abilities to provide acceptable seedlings for forestation. The adverse economic impact of using metam sodium or dazomet ( Table 2) could put the intensive production schedule at risk, leading to failures in providing sufficient numbers of high quality seedlings. As detailed in the nomination, significant research is on going to find MB alternatives that will meet the needs of forest seedling nurseries, but this industry's requirement for MB in the near future is critical. The U. S. nomination for MB for the forest seedling sector is only for those areas that face moderate to severe pest pressure because alternatives are not feasible in these areas. Page 3 TABLE 1. REGION, KEY PESTS, AND CRITICAL NEED FOR METHYL BROMIDE Region Key Pests Critical Need for Methyl Bromide South: Alabama, Arkansas, Georgia, Florida, Louisiana, Mississippi, North Carolina, Oklahoma, South Carolina, Tennessee, Texas, Virginia Auburn University Southern Forest Nursery Mgt. Coop. ( CUE 02 0003) International Paper ( CUE 02 0007) ( also a member of Auburn University consortium) Weyerhaeuser South ( CUE 02 0021) ( also a member of Auburn University consortium) Diseases: Plant fungal pathogens such as species of Fusarium, Alternaria, Phytophthora, Pythium, Rhizoctonia, and Macrophomina,

Weeds: Yellow nutsedge ( Cyperus esculentus), purple nutsedge ( Cyperus rotundus) At moderate to severe pest pressure only MB can effectively control the target pests found in the Southern U. S. MB applications in forest seedling nurseries are typically made using 67: 33 or 50: 50 mixtures with chloropicrin as broadcast application with plastic tarps.

West: California, Idaho, Kansas, Nebraska, Oregon, Utah, Washington Western Forest and Conservation Public Nursery Association ( CUE 02 0008) Nursery Technology Cooperative ( CUE 02 0009) Weyerhaeuser West ( CUE 02 0022) Diseases: Plant pathogens, such as Pythium spp., Fusarium spp., Cylindrocladium spp., Phytophthora spp., and a newly identified disease, Sudden Oak Death, caused by Phytophthora ramorum Weeds: Yellow nutsedge ( Cyperus esculentus) At moderate to severe pest pressure only MB can effectively control the target pests found in the Western U. S. MB applications in forest seedling nurseries are typically made using 67: 33 or 50: 50 mixtures with chloropicrin as broadcast application plastic tarps.

North: Illinois, Indiana, Kentucky, Maryland, Michigan, Missouri, New Jersey, Ohio, Pennsylvania, West Virginia, Wisconsin Illinois Dept. Nat. Res. Nursery Program ( CUE 02 0011) Northeastern Forest and Conservation Nursery Association ( CUE 02 0032) Michigan Seedling Association ( CUE 02 0039) Diseases: Plant fungal pathogens such as species of Fusarium, Alternaria, Phytophthora, Pythium, Rhizoctonia, and Macrophomina, which can cause severe outbreaks of root rots and damping off diseases. At moderate to severe pest pressure only MB can effectively control the target pests found in the Northern U. S. MB applications in forest seedling nurseries are typically made using 67: 33 or 50: 50 mixtures with chloropicrin as broadcast application plastic tarps.

ECONOMIC IMPACTS In order to determine whether a proposed alternative to MB is economically feasible in those situations where technically feasible alternatives exist, the U. S. took a ` weight of the evidence' or ` portfolio' approach. Rather than rely on a single indicator or even a series of indicators, each with a ` bright line', the situation of the applicant with respect to three measures was assessed. The three measures selected for consideration were: loss per hectare; loss per kilogram of MB; and loss as a percent of net cash returns ( profit loss is not included partly because many nurseries are publicly owned and seedling prices or production costs are subsidized). These measures were selected because information needed to support them was fairly readily available and because they describe different aspects of potential loss.

When evaluating the case made by each application, expert economic judgement was used to determine whether each loss ( or change in profit margin) was: significant, not significant, or borderline. Once decisions on individual measures were reached, an overall assessment was made which included the individual measures.

Other impacts on the environment from the activity were also taken into consideration, at least qualitatively, where appropriate. These impacts included only those conferring significant social benefits in the form of environmental improvements which were not otherwise captured in the application. For example, a major use Page 4 of forest seedlings is in reforestation, an activity with significant social benefits to the environment which are not reflected in applicant level economic indicators. A higher cost of seedlings would reduce the overall amount of reforestation with a concomitant reduction in air quality, stream clarity, habitat, etc.

The original U. S. nomination presented data showing that the next best alternative to MB is not economically feasible in the circumstances of each of the nominated states/ regions. Total losses are similar for both dazomet and metam sodium, which are considered the next best alternatives to MB. Quantifiable losses originate from yield losses and cost increases. Dazomet has slightly smaller yield losses than metam sodium, but slightly higher treatment costs, with the result that losses are equivalent for these two alternatives.

In the Southern U. S., a yield loss of 5% would be expected from using metam sodium or dazomet, and operating costs are expected to increase 11 15%. This translates into an expected revenue loss of US$ 3700 per hectare, a 12% loss in gross revenues, and a 27% loss in net cash revenues, indicating a critical need. Measured as a loss per kilogram of MB used, the loss ranges from US$ 3 to US$ 20, with a likely average of US$ 10 per kilogram.

In the Western U. S., a yield loss of 5% would be expected from using metam sodium or dazomet, and operating costs are expected to increase 2 5%. This translates into an expected revenue loss of US$ 3200 per hectare, a 6% loss in gross revenues, and a 16% loss in net cash revenues, indicating a critical need. Measured as a loss per kilogram of MB used, the likely loss is US$ 14 per kilogram.

In the Northern U. S., a yield loss of 3% would be expected from using metam sodium or dazomet, and operating costs are expected to increase 1 2%. Indirect losses occur due to lengthening of the production cycle, which results in less land in production and more in fallow or longer time for seedlings to reach appropriate size. Such losses represent 13% of production. These losses translate into an expected revenue loss of US$ 11,120 per hectare, a 16% loss in gross revenues, and a 67% loss in net cash revenues, indicating a critical need. Measured as a loss per kilogram of MB used, the likely loss is US$ 32 per kilogram.

While direct yield losses are similar across the regions, mainly because the same studies were used to predict impacts, the range of losses in the studies is rather large because both dazomet and metam sodium provide inconsistent pest control. Changes in production costs arise due to differences between the costs of MB and the alternatives, shifts in the production cycle ( increasing the frequency of fumigation or lengthening the fallow period) and additional expenses such as supplementary irrigation. These costs vary across regions and within the Western region, which is highly diverse, because of differences in pests, production systems and regional differences in costs of water and labor. Costs are higher in the South, in part because warmer temperatures increase pest pressure. Page 5 TABLE 2. MEASURES OF ECONOMIC IMPACT OF USING DAZOMET OR METAM SODIUM IN PLACE OF METHYL BROMIDE ON TREE SEEDLING NURSERIES IN THE U. S. A Loss Measures South Auburn University Southern Forest Nursery Mgt. Coop. ( CUE 02 0003) International Paper ( CUE 02 0007) Weyerhaeuser South ( CUE 02 0021) West Western Forest and Conservation Public Nursery Association ( CUE 02 0008) Nursery Technology Cooperative ( CUE 02 0009) Weyerhaeuser West ( CUE 02 0022) North Illinois Dept. Nat. Res. Nursery Program ( CUE 02 0011) Northeastern Forest and Conservation Nursery Association ( CUE 02 0032) Michigan Seedling Association ( CUE 02 0039)

Direct Yield Loss Likely 5% loss 3% gain to 13% loss Likely 5% loss 3% gain to 13% loss Likely 3% loss 2% gain to 13% loss Loss per Hectare Likely US$ 3700 loss US$ 1060 6670 loss Likely US$ 3200 loss US$ 150 gain to US$ 7660 loss Likely US$ 11,120 loss US$ 3330 12600 loss Loss per Kilogram MB Likely US$ 10 loss US$ 3 20 loss Likely US$ 14 loss US$ 1 gain to US$ 26 loss Likely US$ 32 loss US$ 9 to US$ 37 loss Loss as a % of Gross Revenue Likely 12% loss 3 to 22% loss Likely 6% loss 1% gain to 15% loss Likely 16% loss 5 to 19% loss Loss as a % of Net Cash Returns Likely 27%

8 to 49% loss Likely 16% loss 1% gain to 27% loss Likely 67% loss 20 to 76% loss Change in Profit Margins Not Available Not Available Not Available aDazomet and metam sodium have similar total impacts. cChange results from different costs of alternatives, additional pesticide applications, changes in production patterns and additional equipment.

RESPONSE TO QUESTIONS FROM MBTOC/ TEAP 1. The Party is requested to detail the reasoning and assumptions used to calculate the nominated amount.

Details of the reasoning and assumptions used to calculate the nominated amount are shown in Table 5.

The methodology used by the U. S. to calculate the nominated amount of MB carefully scrutinized applications from the user community and took out ( 1) double counting, ( 2) any requested growth beyond historical hectares planted ( Table 4), and ( 3) requested amounts that fall under QPS. Furthermore, the U. S. adjusted the requests from the user community, when they had not already done so, to change the amount of MB nominated to account for ( 1) only the area where pest pressure cannot be controlled by alternatives, ( 2) the area where regulatory constraints limit adoption of alternatives, such as buffers near inhabited areas, and ( 3) the area where soil/ geological features limit use of alternatives, such as groundwater contamination in areas with karst topography. The nominated amount Page 6 incorporates minimum efficacious use rates, mixtures of MB with chloropicrin, and the use of tarps to improve efficacy and reduce emissions.

2. The Party is requested to provide information on what proportion of the MB nominated could be offset by use of non MB alternatives such as substrate production and containerized plants.

An economic analysis suggests that costs associated with changing to substrate production and containerized plants are prohibitive and therefore the proportion of MB nominated could not be offset by using these alternatives ( details of analysis are provided in the Appendix to this document). Here, the U. S. is providing additional information on a MB alternative, the production of forest tree seedlings in containers, rather than in outdoor beds. The U. S. nomination for forest tree seedling nurseries addressed the two chemical and eight non chemical MB alternatives that were identified by MBTOC that was created for all Parties for the CUE process.

The forest tree nursery industry produces millions of bareroot seedlings each year for reforestation, forest establishment, fiber production, and wildlife, conservation, and recreational uses. Generally, use of containers rather than nursery beds can reduce the reliance on fumigants through the use of sterile medium that is initially free of pathogens, insects, nematodes, and weeds ( Seymour, 2000). During the growing season however, there is a critical requirement to control pests in containers, including weeds ( Barnett and McGilvrary, 1997), although MB would not be required. Production costs can be higher for container growth depending on nursery location and conditions, and start up costs in the transition of bed to container systems are high, especially considering the low profit margin ( sometimes negative profits for public nurseries) for forest tree seedling nurseries. Increased costs of container production include more intensive management and more labor than bed production. Containerized seedlings are most effective in the South in niche environments, such as reforestation or reclamation of harsh sites, including mine spoil reclamation and very droughty soils ( Lowert, 2003, personal communication). In these situations containerized seedlings may survive and grow better than bareroot seedlings.

Total costs can be 2.5 times higher for container seedlings ( versus bareroot plants), and may be even higher when shipping costs are included ( Appendix, below). According to one source ( Darrow, 2002 personal communication  see Appendix) the transition from bed to container production requires additional capital and operating costs. High production nurseries may also have higher material costs, e. g., the need to use more expensive multi pot containers, which reduce air circulation around roots and require technology to provide additional air ( Barnett and McGilvrary, 1997). According to another source ( Lowert, 2003, personal communication), shipping costs alone can increase the cost of containerized seedlings by 10% ($ 3.70 per thousand).

The majority of forest seedlings are produced using bareroot systems. The high cost of containerized seedlings combined with no growth or survival advantage ( see Appendix Table D) results in little demand from seedling buyers. This lack of demand is reflected in the composition of one major seedling producer's 2003 04 seedling crop, in which only 3.2 million seedlings ( 1%) out of a 302 million crop are containerized ( Lowerts, 2003, personal communication). In 2000, the U. S. Forest Service reported that production at its Coeur d'Alene ID nursery was 16 million bareroot seedlings annually in beds from 52 hectares, and 4 million seedlings annually from containers in 17 greenhouses on 14 hectares ( http:// www. fs. fed. us/ ipnf/ nurs/ wwwpages/ wwwpage. htm ). Page 7 TABLE 3. AVERAGE YEARLY HEIGHT GROWTH AND SURVIVAL OF CONTAINERIZED AND BAREROOT SEEDLINGS PLANTED DURING THE WINTER PERIOD, NOVEMBER TO MARCH A Age Years % Bareroot Survival Average Height ( ft) Bareroot % Containerized Survival Average Height ( ft) Containerized 1 95 3.8 96 3.3 2 95 8.5 95 7.7 3 94 13.6 95 12.8 aIn house research conducted by International Paper ( personal communication from George Lowerts, 2003)

The use of container plants in forestry is limited by terrain, and the feasibility and cost of transporting seedlings to the planting site. In many forests areas in the U. S., planting is done by hand on challenging terrain, with seedlings carried in by individuals who transport the seedling in backpacks to planting sites. Using container seedlings would require much greater transportation and labor costs; compared to bareroot seedlings and can raise planting costs in a large number of areas. One study found that daily planting decreased from 9.7 hectares per day with bareroot seedlings to 7.3 hectares per day with containerized seedlings without increasing planting crew size ( Lowert, 2003, personal communication). As a result, the overall cost of planting containerized seedlings could increase by 25% due to lower production rates or increased planting crew size. Table 3 demonstrates similar survival and height between container and bareroot plants with the additional negative impact of increased costs due to transportation and planting.

3. It is also requested that the Party consider recalculating the quantity nominated, consistent with the use of emission control technologies coupled with minimizing MB dosages, such as applied in conjunction with chloropicrin where feasible.

The nomination submitted considered the use of emission control technologies applied in conjunction with chloropicrin. Forest seedling growers in the regions requesting this exemption routinely produce these crops using plastic tarpaulins, which reduce MB emissions. Although data are not available for the entire US, in California 93% of MB pre plant applications are made under plastic tarps ( personal communication, Paul Niday, TriCal Corp.). The 7% of usage that is not tarped is applied by deep shank injection for orchard replant. Also, the nominated amount assumes that growers would continue to use mixtures of MB with chloropicrin ( typically 67: 33 or 50: 50; see Table 1), a reduction in the amount of MB used. Recalculation of the nomination amount was not necessary because the original U. S. nomination already accounts for these factors 4. The nomination did not give comparative data, except some yields, to determine the technical feasibility of many alternatives and their comparative performance compared to MB under the circumstances of the nomination.

There is limited data available reporting quality reduction in nurseries from the use of MB alternatives. Yield data comparing performance for identified chemical alternatives, such as Telone and/ or chloropicrin are strong indicators of the effect of these alternatives compared with MB. Economic analysis provided in the original nomination for this sector and highlighted in this document ( Table 2) suggests that economic losses would be significant if alternatives were to replace MB. As previously mentioned, in at least one set of trials for chloropicrin efficacy, beds had to be abandoned due to nutsedge infestation ( Littke, 2003, personal communication). These trials also required increased use of herbicides to control nutsedge, and were not uniformly successful in doing so.

5. The CUN finds that two chemical alternatives are considered technically feasible, but does not discuss the feasibility of utilizing substrates and containerized plants for forest seedling production. Containerized plant systems are quite widely in use. Page 8 The U. S. response to the comment that containerized plant systems are in wide use is elaborated in Comment/ Response # 2, above, and in the Appendix to this document.

TABLE 4. HISTORICAL USE OF METHYL BROMIDE IN THE FOREST SEEDLING SECTOR*

Historical Use Average Use Rates ( kg/ ha) Total Amount ( kg) Area Treated ( ha)

1997 351 446,481 1,224 1998 346 454,468 1,280 1999 333 486,650 1,358 2000 314 453,990 1,333 2001 305 436,452 1,307 * Acres planted in U. S. and percent of U. S. acreage requested is not available. Source: Rates, amounts, and area treated are from applicants' information.

TABLE 5. CALCULATION OF THE NOMINATED AMOUNT OF METHYL BROMIDE IN THE FOREST SEEDLING SECTOR Calculation of Nominated Amount 0003   Auburn Southern Forest Nursery 0007   International Paper 0008   Western Forest & Conservation Public Nursery Assoc. 0009   Nursery Technology Cooperative 0011   Gale Rampley Hectares ( ha) 656 109 61 202 16 % of Regional hectares ( ha)( A) Not Available Not Available Not Available Not Available Not Available Applicant Request for 2005 Kilograms ( kg) of MB 246,032 41,730 20,412 52,390 4,264 Double Counted hectares ( ha)( B) 176         Growth / Increasing Production hectares ( ha)( C)       ( 14) 3 Quarantine and Pre Shipment hectares ( ha)( D) 240 54 30 101 6 Adjustment s to Request Adjusted Hectares Requested ( ha)( E) 240 55 31 101 7 Key Pest Impacts (%)( F) 100 100 100 100 100 Regulatory Impacts (%)( G)           Soil Impacts (%)( H)           Impacts to Adjusted Hectares Total Combined Impacts (%)( I) 100 100 100 100 100 Qualifying Area ( ha)( J) 240 55 31 101 7 Use Rate ( kg/ ha)( K) 375 382 336 259 263 CUE Amount Nominated ( kg)( L) 90,005 20,865 10,206 26,195 1,706 % Reduction from Initial Request ( M) 63 50 49 50 56 Page 9 TABLE 5. CALCULATION OF THE NOMINATED AMOUNT OF METHYL BROMIDE IN THE FOREST SEEDLING SECTOR ( CONTINUED)

Calculation of Nominated Amount 0021   Weyerhaeuser ( SE) 0022   Weyerhaeuser ( NW) 0032   N. E. Forest & Conservation Nursery Assoc. 0039   Michigan Seedling Association Hectares ( ha) 67 94 97 34 % of Regional hectares ( ha)( A) Not Available Not Available Not Available Not Available Applicant Request for 2005 Kilograms ( kg) of MB 22,453 24,752 33,112 9,144 Double Counted hectares ( ha)( B)         Growth / Increasing Production hectares ( ha)( C) 1 29 11   Quarantine and Pre Shipment hectares ( ha)( D) 33 33 43 17 Adjustmen ts to Request Adjusted Hectares Requested ( ha)( E) 33 32 43 17 Key Pest Impacts (%)( F) 100 100 100 100 Regulatory Impacts (%)( G)         Soil Impacts (%)( H)         Impacts to Adjusted Hectares Total Combined Impacts (%)( I) 100 100 100 100 Qualifying Area ( ha)( J) 33 32 43 17 Use Rate ( kg/ ha)( K) 336 263 341 269 CUE Amount Nominated ( kg)( L) 11,090 8,562 14,728 4,572 % Reduction from Initial Request ( M) 51 66 56 50 Sum of all CUE Nominations in Sector ( kg)( N) 187,929 Multiplier for Margin of Error ( O) 1.0244 Total U. S. Sector Nomination ( kg)( P) 192,515 Page 10 Footnotes for Table 5:

Values may not sum exactly due to rounding.

A. Percent of regional hectares is the area in the applicant's request divided by the total area planted in that crop in the region covered by the request as found in the USDA National Agricultural Statistics Service ( NASS). Note, however, that the NASS categories do not always correspond one to one with the sector nominations in the U. S. CUE nomination ( e. g., roma and cherry tomatoes were included in the applicant's request but were not included in NASS surveys). Values greater than 100 percent are due to the inclusion of these varieties in the U. S. CUE request that were not included in the USDA NASS: nevertheless, these numbers are often instructive in assessing the requested coverage of applications received from growers. B. Double counted hectares is the area counted in more than one application or rotated within one year of an application to a crop that also uses MB. In this sector two firms submitted individual applications and had portions of their operations included in a consortium application. This double counting has been removed. C. Growth / increasing production hectares is the amount of area requested by the applicant that is greater than that historically treated or treated at a higher use rate. Values in parentheses indicate negative values and are shown to demonstrate a trend, but are not used in further calculations. Growth has been removed. D. Quarantine and pre shipment ( QPS) hectares is the area in the applicant's request subject to QPS treatments. Up to 50% of the requested amount has been deducted as falling under the quarantine/ preshipment exemption. E. Adjusted hectares requested is the hectares in the applicant's request minus the hectares affected by double counting, growth / increasing production, and quarantine and pre shipment. F. Key pest impacts is the percent (%) of the requested area with moderate to severe pest problems. Key pests are those that are not adequately controlled by MB alternatives. Because this activity is provision of nursery stock it is considered vital that the plants be pest free. G. Regulatory impacts is the percent (%) of the requested area where alternatives cannot be legally used ( e. g., township caps). H. Soil impacts is the percent (%) of the requested area where alternatives cannot be used due to soil type ( e. g., heavy clay soils may not show adequate performance). I. Total combined impacts is the percent (%) of the requested area where alternatives cannot be used due to key pest, regulatory, or soil impacts. In each case the total area impacted is the area, which is impacted by one or more of the individual impacts. For each application the assessment was made by biologists familiar with the specific situation and able to make judgments about the extent of overlap of the impacts. For example, in some situations the impacts are mutually exclusive   in heavy clay soils 1,3 D will not be effective because it does not penetrate these soils evenly, but none of the heavy soil areas will be impacted by township ( regulatory) caps because no one will use 1,3 D in this situation, so this soils impact must be added to the township cap regulatory impact in a California application. In other words there is no overlap. In other situations one area of impact might be a subset of another impact. In these cases, the combined impact is equal to the largest individual impact. J. Qualifying area is calculated by multiplying the adjusted hectares requested by the total combined impacts. K. Use rate is the requested use rate for 2005. This rate is typically based on historical averages. In some cases, the use rate has been adjusted downward to reflect current conditions. Half of the applications have had their use rate adjusted down. L. CUE amount nominated is calculated by multiplying the qualifying area by the use rate. M. Percent reduction from initial request is the percentage of the initial request that did not qualify for the CUE nomination. N. Sum of all CUE nominations in sector. Self explanatory. O. Multiplier for margin of error. This amount is one percentage point of the original ( 1991) baseline amount. This factor is intended to compensate for the compounding influence of using the low end of the range for all input parameters in the calculation of the US nomination ( i. e., using the lowest percent impact on the lowest number of acres at the lowest dosage is likely to result in values that are unrealistically too small). The U. S. nomination included some sectors for 100% of the amount requested, therefore the portion of the multiplier from these sectors were added equally across all other sectors resulting in a final multiplier of 1.0244, or a 2.44% increase from the calculated amount, to these remaining sectors. P. Total U. S. sector nomination is calculated by multiplying the sum of all nominations in this sector by the margin of error multiplier. Page 11 DEFINITIONS THAT MAY BE RELEVANT TO THIS CUN Source of yield loss estimates Where published studies of yield losses under conditions of moderate to severe key pest pressure were not available ( the situation for which the U. S. is requesting continued use of MB), the U. S. developed such estimates by contacting university professors conducting experiments using MB alternatives in the appropriate land grant institutions. The experts were asked to develop such an estimate based on their experience with MB and with alternatives. The results of this process were used when better data were not available.

Source of buffer restriction implications for methyl bromide use Estimates of the impact of buffers required when using some MB alternatives on the proportion of acreage where such alternatives could be used were developed from confidential information submitted to EPA in support of a registration application for a MB alternative. Because at the time of the analysis, a request to reduce the size of the required buffer for some alternatives was under consideration, a smaller buffer was selected for the analysis. Since that time the size of the regulatory buffer has been reduced so that it now conforms to the buffer selected for this analysis.

Source of area impacted by key pests estimates One of the important determinants of the amount of MB requested has been the extent of area infested with ` key pests', that is, pests which cannot be controlled by alternatives to MB when such pests are present at moderate to severe levels. Because there are few surveys that cover substantial portions of the areas for which MB is requested, we have relied on a variety of sources in addition to the surveys. These sources include websites of land grant universities; discussions with researchers, both those employed by USDA in the Agricultural Research Service ( ARS) and those at land grant universities; discussions with growers whose operations cover widely different locations encompassing different incidences of key pests; information from pesticide applicators; and, information taken from the applications themselves.

Source of area impacted by regulations estimates There are two main sources used to develop the estimate of area impacted by regulations. First, for the impact of Township caps in California we have used a series of papers by Carpenter, Lynch, and Trout, supplemented by discussions with Dr. Trout to ensure that any recent regulatory changes have been properly accounted for. Second, the estimate of the area impacted by buffers, is described above.

Source of area impacted by soil type estimates First, for the area impacted by karst topography, estimates were developed and mapped by he Florida Department of Environmental Protection. The area of California used for agriculture and which is made of clay soils unsuitable for pest control with a MB alternative has been determined by discussions with agricultural researchers and agricultural extension agents in California, and discussion with other knowledgeable individuals such as pesticide applicators. The estimates for California understate the areas in which alternatives to MB are not suitable because no effort was made to estimate the extent of hilly terrain where currently available substitutes cannot be applied at uniform dosages. Page 12 Source of area impacted by combined impacts estimate Combined impacts were determined on a case by case basis for each specific crop/ location combination after consultation with individuals knowledgeable with the specific circumstances. The nature of the individual impacts is such that in some situations they are independent of each other, in some they are mutually exclusive, and in some cover identical areas. It was not, therefore, possible to have a formula that would arrive at an appropriate estimate of combined impacts. A more complete description is found in the footnotes to the ` calculation' table REFERENCES Barnett, J. P. and McGilvrary, J. M. 1997. Practical guidelines for producing longleaf pine seedlings in containers. Gen. Tech. Rep. SRS 14. Asheville, NC. U. S. Department of Agriculture, Forest Service, Southern Research Station. 28 p. http:// www. bugwood. org/ container/ guidelines. html Darrow, K. 2002. Personal communication ( see Appendix)

Littke, W. 2003. Personal communication.

Lowerts, G. 2003. Personal communication.

Seymour, N. G. 2000. Guide to establishing a nursery in Alberta   container growing. Alberta ( Canada). http:// www. agric. gov. ab. ca/ crops/ trees/ nursery8. html. Page 13 APPENDIX : Estimated Costs Of Converting A Loblolly Forest Tree Seedling Nursery From Soil Based To Containerized Soilless Culture1 The costs below are based on the conversion of a 10 million bare root seedling, soil based, nursery to a container, soilless, nursery for the raising of Loblolly pine seedlings in the southern USA. The cost estimates include estimates of additional expenditures ( over and above $. 04 per seedling cost for soil based system) for:

A. Capital Infrastructure B. Operating Costs Limitations of Analysis: There are also expected to be additional shipping costs, due to the larger size and weight of containerized plants, but estimating these costs were beyond the scope of this analysis. Economy of scale can be significant and regional costs vary, making it difficult to provide a precise cost.

Additional Note: The capital costs associated with conversion from a soil based to a soilless nursery are much less than the capital costs of establishing a new soilless nursery. All of the basic infrastructure and much of the equipment would already be in place with a soil based nursery.

A. Capital Infrastructure: Many of the facilities required for the operation of a soil based seedling nursery are required for a soilless nursery, so conversion costs and the conversion costs are Conversion cost: Water supply $ 0 Power $ 0 Buildings $ 0 Landscaping/ levelling/ roads $ 0 Equipment  assuming no trade ins $ 100,000 Nursery structures + irrigation $ 130,000 B. Operating costs: Working capital requirements are greater in a soilless nursery than a soil based nursery as more labor is used. The cost of conversion from a soil based nursery to a soilless nursery should include the need for additional working capital.

Working Capital: additional container system cost $ 150,000 ( over and above ~$ 50,000 cost for soil based system) containers $ 410,000 Page 14 C. Land The soil based nursery requires 13.3 hectares exclusive of buildings, storage and administrative area. The soilless nursery requires 4 hectares for the same production.

Assuming the soil based nursery owner is able to sell or exchange the surplus land, the change from soil based to soilless will be a source of revenue. A review of land prices in the southern USA, in localities where forest tree nurseries are situated reveals an average of $ 12,350 per hectare.

Land Savings: Land ( 9.3 hectares at $ 12,350 per hectare) ($ 114,855)

TABLE D. ANALYSIS OF NET COSTS: CONVERTING 10 MILLION SEEDLING NURSERY FROM BAREROOT TO CONTAINERIZED, SOILLESS CULTURE Capital Cost Years of Use* Annual Cost Cost per Seedling Equipment $ 100,000 10 $ 11,723 $ 0.0012 Nursery Structures $ 130,000 10 $ 15,240 $ 0.0015 Running Container System $ 150,000 $ 0.015 Containers $ 410,000 $ 0.041 Total Additional Cost** $ 586,963 $ 0.059 Land rent savings*** ($ 3,450) ($ 0.0003)

Net additional cost $ 0.0583 Base production cost ( for bare root and soilless system) $ 0.04 Total Cost per Seedling $ 0.0983 * Incorporates real interest cost at 3% per year. ** Does not include additional cost of shipping due to larger and heavier containers. *** Using land capitalization rate of 3%.

Conclusion: Converting to a soilless containerized system would increase the cost of production by approximately 250%, and could be higher when the increased cost of shipping containerized seedlings is included.

1 ( Based on communication with Kevin Darrow, Sept. 2002)


[Federal Register Volume 81, Number 89 (Monday, May 9, 2016)]
[Notices]
[Pages 28088-28089]
[FR Doc No: 2016-10901]

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DEPARTMENT OF HOMELAND SECURITY

Coast Guard

[Docket No. USCG-2016-0258]

Information Collection Request to Office of Management and
Budget; OMB Control Number: 1625-0049

AGENCY: Coast Guard, DHS.

ACTION: Sixty-day notice requesting comments.

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SUMMARY: In compliance with the Paperwork Reduction Act of 1995, the

U.S. Coast Guard intends to submit an Information Collection Request
(ICR) to the Office of Management and Budget (OMB), Office of
Information and Regulatory Affairs (OIRA), requesting approval of
revisions to the following collection of information: 1625-0049,
Waterfront Facilities Handling Liquefied Natural Gas (LNG) and
Liquefied Hazardous Gas (LHG). Our ICR describes the information we
seek to collect from the public. Before submitting this ICR to OIRA,
the Coast Guard is inviting comments as described below.

DATES: Comments must reach the Coast Guard on or before July 8, 2016.

ADDRESSES: You may submit comments identified by Coast Guard docket
number [USCG-2016-0258] to the Coast Guard using the Federal
eRulemaking Portal at http://www.regulations.gov. See the ``Public
participation and request for comments'' portion of the SUPPLEMENTARY
INFORMATION section for further instructions on submitting comments.
    A copy of the ICR is available through the docket on the Internet
at http://www.regulations.gov. Additionally, copies are available from:
COMMANDANT (CG-612), ATTN: PAPERWORK REDUCTION ACT MANAGER, U.S. COAST
GUARD, 2703 MARTIN LUTHER KING JR AVE SE, STOP 7710, WASHINGTON, DC
20593-7710.

FOR FURTHER INFORMATION CONTACT: Contact Mr. Anthony Smith, Office of
Information Management, telephone<PHONE_NUMBER>, or fax<PHONE_NUMBER>,
for questions on these documents.

SUPPLEMENTARY INFORMATION:

Public Participation and Request for Comments

    This Notice relies on the authority of the Paperwork Reduction Act
of 1995; 44 U.S.C. Chapter 35, as amended. An ICR is an application to
OIRA seeking the approval, extension, or renewal of a Coast Guard
collection of information (Collection). The ICR contains information
describing the Collection's purpose, the Collection's likely burden on
the affected public, an explanation of the necessity of the Collection,
and other important information describing the Collection. There is one
ICR for each Collection.
    The Coast Guard invites comments on whether this ICR should be
granted based on the Collection being necessary for the proper
performance of Departmental functions. In particular, the Coast Guard
would appreciate comments addressing: (1) The practical utility of the
Collection; (2) the accuracy of the estimated burden of the Collection;
(3) ways to enhance the quality, utility, and clarity of information
subject to the Collection; and (4) ways to minimize the burden of the
Collection on respondents, including the use of automated collection
techniques or other forms of information technology. In response to
your comments, we may revise this ICR or decide not to seek approval of
revisions of the Collection. We will consider all comments and material
received during the comment period.
    We encourage you to respond to this request by submitting comments
and related materials. Comments must contain the OMB Control Number of
the ICR and the docket number of this request, [USCG-2016-0258], and
must be received by July 8, 2016.

Submitting Comments

    We encourage you to submit comments through the Federal eRulemaking
Portal at http://www.regulations.gov. If your material cannot be
submitted using http://www.regulations.gov, contact the person in the
FOR FURTHER INFORMATION CONTACT section of this document for alternate
instructions. Documents mentioned in this notice, and all public
comments, are in our online docket at http://www.regulations.gov and
can be viewed by following that Web site's instructions. Additionally,
if you go to the online docket and sign up for email alerts, you will
be notified when comments are posted.
    We accept anonymous comments. All comments received will be posted
without change to http://www.regulations.gov and will include any
personal information you have provided. For more about privacy and the
docket, you may review a Privacy Act notice regarding the Federal
Docket Management System in the March 24, 2005, issue of the Federal
Register (70 FR 15086).

Information Collection Request

    Title: Waterfront Facilities Handling Liquefied Natural Gas (LNG)
and Liquefied Hazardous Gas (LHG).
    OMB Control Number: 1625-0049
    Summary: Liquefied Natural Gas (LNG) and other Liquefied Hazardous
Gases (LHG) present a risk to the public when handled at waterfront
facilities. These rules should either prevent accidental releases at
waterfront facilities or mitigate their results. They are necessary to
promote and verify compliance with safety standards.
    Need: Title 33 CFR part 127 prescribe safety standards for the
design, construction, equipment, operations, maintenance, personnel
training, and fire protection at waterfront facilities handling LNG or
LHG.
    Forms: None.
    Respondents: Owners and operators of waterfront facilities that
transfer LNG or LHG.
    Frequency: On occasion.
    Hour Burden Estimate: The estimated burden has decreased from 6,425
hours to 5,019 hours a year due to a decrease in the estimated annual
number of respondents.

    Authority: The Paperwork Reduction Act of 1995; 44 U.S.C.
Chapter 35, as amended.

    Dated: April 29, 2016.
Thomas P. Michelli,
U.S. Coast Guard, Deputy Chief Information Officer.
[FR Doc. 2016-10901 Filed 5-6-16; 8:45 am]
 BILLING CODE 9110-04-P


[Federal Register: August 7, 2008 (Volume 73, Number 153)]
[Notices]
[Page 46002]
[DOCID:fr07au08-55]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RC08-4-002]

New Harquahala Generating Company, LLC; Notice of Filing

July 30, 2008.
    Take notice that on July 25, 2008, the North American Electric
Reliability Corporation (NERC) submitted for filing in compliance with
Commission Order issued May 16, 2008, upheld the registration of New
Harquahala Generating Company, LLC in the NERC Compliance Registry for
the functions of transmission owner and transmission operator within
the Western Electricity Coordinating Council.
    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.
Anyone filing a motion to intervene or protest must serve a copy of
that document on the Applicant and all the parties in this proceeding.
    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 14 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 e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5 p.m. Eastern Time on August 15, 2008.

Kimberly D. Bose,
Secretary.
 [FR Doc. E8-18056 Filed 8-6-08; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 82, Number 210 (Wednesday, November 1, 2017)]
[Rules and Regulations]
[Pages 50517-50523]
[FR Doc No: 2017-23722]

=======================================================================
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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Chapter I

Final Report: Review of Federal Energy Regulatory Commission
Agency Actions Pursuant to Executive Order 13783, Promoting Energy
Independence and Economic Growth

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Availability of Final Report.

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SUMMARY: This Final Report on the Review of Federal Energy Regulatory
Commission Agency Actions is provided pursuant to Executive Order
13783, Promoting Energy Independence and Economic Growth.

DATES: November 1, 2017.

ADDRESSES: Report available through http://www.ferc.gov.

FOR FURTHER INFORMATION CONTACT:

Nicholas Tackett, Office of Energy Projects, Branch Chief, Division of
Hydropower Licensing, Federal Energy Regulatory Commission, 888 First
Street NE., Washington, DC 20426,<PHONE_NUMBER>
Karin L. Larson, Office of General Counsel, Energy Projects, Federal
Energy Regulatory Commission, 888 First Street NE., Washington, DC
20426,<PHONE_NUMBER>

SUPPLEMENTARY INFORMATION:

FEDERAL ENERGY REGULATORY COMMISSION

Final Report

Review of Federal Energy Regulatory Commission Agency Actions Pursuant
to Executive Order 13783, Promoting Energy Independence and Economic
Growth

I. Executive Summary

    On March 28, 2017, the President signed Executive Order 13783,
titled Promoting Energy Independence and Economic Growth (Executive
Order).\1\ Pursuant to section 2(c) of the Executive Order, on May 12,
2017, the Federal Energy Regulatory Commission (FERC, or the
Commission) submitted to the Office of Management and Budget (OMB) its
plan (Plan) for reviewing its existing regulations, orders, guidance
documents, policies, and any other similar agency action (agency
actions) that potentially burden the development or use of domestically
produced energy resources. On July 26, 2017, pursuant to section 2(d)
of the Executive Order, the head of the Commission submitted a draft
final report detailing the review undertaken and the results of the
review. Given the Commission's status as an independent regulatory
agency, this final report is being submitted on a voluntary basis.\2\
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    \1\ Executive Order 13783, Promoting Energy Independence and
Economic Growth, 82 Fed. Reg. 16093 (Mar. 28, 2017).
    \2\ The Commission is a multi-member, independent regulatory
agency that must follow applicable federal laws to change its rules,
regulations and orders. Because the Commission must ultimately
decide what action, if any, to take in response to the Executive
Order, this report is a Commission staff analysis of the issues
identified for review in the Executive Order and does not
specifically recommend actions nor indicate the timing of any
potential action.
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    Of the agency actions reviewed, this final report identifies nine
agency actions that potentially materially burden the development or
use of domestic energy resources as contemplated by the Executive Order
and clarified by OMB's May 8, 2017 Guidance Memo.\3\ In addition, these
identified agency actions may be addressed in conjunction with the
Commission's ongoing efforts pursuant to Executive Order 13777.
---------------------------------------------------------------------------

    \3\ Memo from Dominic J. Mancini, Acting Administrator, Office
of Information and Regulatory Affairs to Regulatory Reform Officers
and Regulatory Policy Officers at Executive Departments and Agencies
regarding Guidance for Section 2 of Executive Order 13783, titled
``Promoting Energy Independence and Economic Growth.''
---------------------------------------------------------------------------

II. Background

    Section 2 of the Executive Order requires the heads of federal
agencies to immediately ``review all existing regulations, orders,
guidance documents, policies, and any other similar agency actions
(collectively, agency actions) that potentially burden the development
or use of domestically produced energy resources, with particular
attention to oil, natural gas, coal, and nuclear energy resources. Such
review shall not include agency actions that are mandated by law,
necessary for the public interest, and consistent with the policy set
forth in section 1 of this order.''
    On May 8, 2017, OMB issued a Guidance Memo providing additional
information regarding compliance with the Executive Order, in
particular section 2. The Guidance Memo noted that the Executive Order
does not apply to independent agencies as defined in 44 U.S.C. 3502(5),
but encouraged independent regulatory agencies, especially those that
directly regulate the development or use of domestically produced
energy resources, to provide the plan and report that are called for in
section 2 of the Executive Order. The Guidance Memo further encourages
agencies to coordinate their compliance with Section 2 of Executive
Order 13783 with their compliance with Executive Order 13777, which
directs agencies to establish Regulatory Reform Task Forces to evaluate
existing regulations generally and make recommendations to the agency
head regarding their repeal, replacement and modification, consistent
with applicable law.
    In the Plan, the Commission explained that it intended to review
agency actions it has taken pursuant to legislative authority under:
(1) the Natural Gas Act (NGA), 15 U.S.C. 717, et seq.; (2) the Federal
Power Act (FPA), 16 U.S.C. 791a, et seq.; (3) the Interstate Commerce
Act, 49 App. U.S.C. 1 et seq.; (4) the Public Utility Regulatory
Policies Act of 1978 (PURPA), 16 U.S.C. 2601 et seq., and (5) other
statutes for which the Commission's actions on LNG, natural gas
pipeline, and hydropower projects

often require compliance, such as the National Environmental Policy
Act, the Endangered Species Act, the Coastal Zone Management Act, and
the Clean Water Act.

III. Commission Review of Agency Actions Pursuant to Section 2

A. Scope of Review

    Domestic Energy Sources: Section 2 of the Executive Order states
that the review should place particular attention on oil, natural gas,
coal, and nuclear energy resources. In addition, section 1 of the
Executive Order and the Guidance Memo list renewable sources, including
flowing water, as domestic energy sources. Therefore, this final report
considers agency actions that potentially affect not only oil, natural
gas, coal, and nuclear energy resources, but also hydropower and other
renewable generation resources.
    Potentially Material Burdens: Section 2(b) of the Executive Order
states that ``burden'' means ``to unnecessarily obstruct, delay,
curtail, or otherwise impose significant costs on the siting,
permitting, production, utilization, transmission, or delivery of
energy resources.'' Based on the Executive Order's definition of
``burden,'' as informed by the Guidance Memo which highlights agency
actions that ``materially'' affect domestic energy production, this
final report considers an agency action ``material'' if it could: (1)
directly affect the development or use of domestic energy resources; or
(2) have a primary indirect effect on the development or use of
domestic energy resources.\4\ Given the Commission's limited
jurisdiction, none of the Commission's agency actions would materially
affect the design and/or location of drilling or mining of energy
production resources.
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    \4\ The Guidance Memo indicates that agencies should review
actions that both directly and indirectly affect domestic energy
sources. This final report uses the term ``primary indirect effect''
to define the scope of indirect effects that will be considered for
review. A primary indirect effect is an effect that is only one step
removed from a direct effect. In other words, a primary indirect
effect occurs when an agency action affects a factor that, in turn,
affects a domestic energy source.
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    Agency Actions: This final report considers the following types of
binding Commission agency actions in existence as of March 28, 2017
(i.e., the date of issuance of Executive Order 13783): codified
regulations published by the Commission (i.e., 18 CFR); final rules;
public policy statements and guidance documents; and case-specific
orders and opinions that establish policies that are broadly applied
and not otherwise codified by the Commission.\5\
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    \5\ This report does not consider the issue of grants to third
parties to perform agency actions because the Commission does not
issue such grants. Commission staff's analysis included
consideration of information collections, including those subject to
the Paperwork Reduction Act, to the extent that such collections are
within the scope of the agency actions reviewed under the Executive
Order.
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B. Methodology

    This final report identifies and classifies the potentially
relevant agency actions based on: (1) the type of action undertaken;
(2) the energy source potentially affected by that action; and (3)
whether the potential effects of the action are direct or indirect.
    This final report focuses on agency actions in four jurisdictional
areas: (1) hydropower licensing; (2) LNG facility, and natural gas
pipeline and storage facility siting; (3) centralized electric capacity
market policies in PJM Interconnection, L.L.C. (PJM), ISO New England,
Inc. (ISO-NE), and New York Independent System Operator, Inc. (NYISO);
and (4) electric generator interconnection policies.
    Commission actions in these four jurisdictional areas have the
greatest potential to materially burden domestic energy resources as
contemplated under the Executive Order. In particular, the Commission's
hydropower licensing program has the potential to directly affect the
design, location, and development of hydropower resources. In addition,
the Commission's jurisdiction over the siting of LNG terminals and
natural gas pipelines may affect the delivery to market of natural gas,
and have a primary indirect effect on the use of that domestically
produced energy resource.
    Agency actions related to electric capacity market policies and
generator interconnection policies may have a primary indirect effect
on the development, retention, or retirement of domestic energy
resources. As the Commission has recently recognized in its ongoing
efforts concerning the interplay of wholesale electric markets and
state policy, the centralized electric capacity markets in PJM, ISO-NE,
and NYISO are intended to ensure long-term resource adequacy by sending
accurate price signals for investment in electric capacity resources,
when and where needed. By signaling the value of capacity, including
the potential need for new generation resources, these markets serve a
function in those regions that would otherwise typically be performed
through integrated resource planning, often before a state public
service commission. As a result, Commission actions related to electric
capacity market policies could have a primary indirect effect on the
development and use of generation resources.
    Finally, agency actions involving generator interconnection
policies could have a primary indirect effect on the development of
domestic energy resources. For example, a wind or solar generator at
utility scale typically must interconnect to the transmission grid in
order to deliver the electricity produced by those domestic energy
resources to the wholesale purchaser. If Commission policies or actions
lead to a delay in interconnection or otherwise affect the generator's
ability to interconnect, then the project developer may not develop
that energy resource, which would impact the development or use of
domestic energy resources.
    This final report does not review agency actions involving oil and
natural gas pipeline rates; electric energy and ancillary service rates
and market policies; \6\ electric transmission rates, including return
on equity issues; demand response resources; mergers; enforcement;
reliability; backstop transmission siting authority; and the Public
Utilities Regulatory Policies Act. Commission action in these areas may
indirectly impact the design, location, development, or use of domestic
energy resources, but would not have a primary indirect effect, as
discussed above.
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    \6\ Commission actions on energy and ancillary service market
rules are less directly related to the development and use of
domestic energy resources than Commission actions on centralized
capacity market rules. While energy and ancillary service markets
have an effect on the economic viability and day-to-day use of
generation resources, the market rules established by the Commission
are intended to ensure recovery of variable costs (e.g., fuel costs)
for marginal units, rather than to be the primary source of fixed
cost recovery for new generation resources. That is, in regions that
do not have capacity markets, there is an additional mechanism to
address fixed cost recovery typically administered by the relevant
state regulatory commission, in the case of investor-owned public
utilities, or the management of public power utilities.
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    Pursuant to the Guidance Memo's recommendation, this effort with
respect to Executive Order 13783, to the extent appropriate, was
coordinated with the Commission's Regulatory Reform Task Force created
pursuant to Executive Order 13777.\7\
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    \7\ As with Executive Order 13783, independent regulatory
agencies like the Commission are not subject to Executive Order
13777, but are encouraged to comply.
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    This final report discusses those agency actions that rose to the
level of a potential material burden as contemplated by the Executive
Order and clarified by the Guidance Memo. For hydropower licensing and
the LNG

and natural gas transportation facilities siting programs, the
Executive Order review process revealed potentially burdensome agency
actions related to regulations promulgated by the Commission. For
electric capacity markets and generator interconnection, the Executive
Order review process revealed potentially burdensome agency actions
related to Commission rulemaking orders and case-specific orders, which
typically did not result in the promulgation of regulations. This final
report identifies steps the Commission may consider, to the extent
permitted by law, to alleviate or eliminate the aspects of the agency
actions that may burden the development or use of domestically produced
energy resources.

C. Discussion

1. Hydropower Licensing
    Under Part I of the FPA, the Commission has the exclusive authority
to issue licenses, small capacity exemptions (up to 10 megawatts (MW)),
and conduit exemptions for non-federal hydropower projects. The
Commission currently regulates over 1,600 licensed or exempted
hydroelectric projects, representing about 56,000 MW of authorized
installed capacity, which is more than half of all developed hydropower
in the United States.
    The Commission is responsible for coordinating and managing the
processing of hydropower project license and exemption applications, as
well as applications for preliminary permits (under which permittees
study proposed projects). This includes determining the effects of
constructing, operating, and maintaining hydropower projects on
environmental resources, and the need for the project's power. Pursuant
to the FPA, issues considered during the review of license applications
include power production; fish, wildlife, recreation, and other
environmental issues; flood control; irrigation; and other water uses.
Various statutory requirements also give other agencies a significant
role in project development, and several state and federal agencies
have mandatory authorities that limit the Commission's control of the
cost and time required for licensing.
    Following the issuance of a license or exemption, the Commission
oversees compliance with the terms and conditions of the license/
exemption for the duration of the license. This includes processing the
filing of plans, reports, and license amendments. Additionally, the
Commission must determine if it has jurisdiction over proposed or
unlicensed operating projects; determine and assess headwater benefit
charges; approve transfers of licensed projects; resolve complaints
alleging noncompliance with license and exemption conditions; and act
on applications for license surrenders.
    The Commission also is responsible for ensuring that the water-
retaining features of hydropower projects are designed, constructed,
operated, and maintained using current engineering standards and
federal guidelines for dam safety. Commission staff inspects projects
to investigate potential dam safety problems and, every five years, a
Commission-approved independent consulting engineer must inspect and
evaluate projects with dams higher than 32.8 feet or with a total
storage capacity of more than 2,000 acre-feet. The Commission also
requires licensees to prepare emergency action plans and conducts
training sessions on how to develop and test these plans.
    The vast majority of agency actions relating to the Commission's
hydropower program do not present a material burden to hydropower
resources. Specifically, most agency actions: (1) are necessary to
administer the Commission's hydropower program and process hydropower
license applications in an orderly manner; and/or (2) do not negatively
affect the development of hydropower resources. As outlined below,
however, this final report identifies three areas where potential
material burdens may exist: licensing processes; exemption processes;
and determinations on deficient applications.
a. Licensing Processes
i. ILP Default Regulation
    The Commission's regulations include three hydropower licensing
processes for applicants: the Integrated Licensing Process (ILP), the
Traditional Licensing Process (TLP), and the Alternative Licensing
Process (ALP). The Commission's regulations assign the ILP as the
default process for all license requests, and an applicant must
specifically request and justify the use of either the TLP or ALP.
Assigning the ILP as the default process could be materially burdensome
due to: (1) the time and costs associated with obtaining the
Commission's approval to use the TLP or ALP; and (2) in the event the
Commission denies the request to use the TLP/ALP, there may be
additional time and costs associated with the ILP, due to the
structured nature of the process. The level of burden caused by the ILP
default regulation is largely project-specific, and may be negligible/
non-existent for complex proceedings that could benefit from a more
structured process such as the ILP. However, any material burden could
be alleviated by making the ILP optional, and removing the requirement
to seek Commission authorization to use the TLP and ALP (see 18 CFR
4.30, 5.1, 5.3, 5.8, 16.1).
ii. Pre-Filing Application Requirement
    In the final stages of the Commission's pre-filing process for
hydropower projects, the Commission's regulations require a potential
applicant to submit a draft license application or preliminary
licensing proposal before submitting a final license application (18
CFR 4.38(c)(4) and 5.16, respectively). The Commission's regulations
include minimum filing requirements for these documents (e.g., study
results, analyses, and environmental measures), and a stakeholder
review process. The requirement to file the draft application and
preliminary licensing proposal may be materially burdensome in terms of
the cost and delay associated with the preparation of the documents and
the stakeholder review process. To eliminate material burdens, the
Commission could consider revising its regulations to make this aspect
of the pre-filing process optional for license applicants.
iii. Pre-Filing Schedule
    The ILP contains comment and filing deadlines throughout the pre-
and post-filing application process to ensure a structured approach to
hydropower licensing. The ILP, however, may be materially burdensome in
terms of the schedule established for the pre-filing process (3-3.5
years total). To alleviate this burden, the Commission could consider
certain comment and filing deadline reductions to allow for an overall
time savings of three months: (1) reduce the time that an applicant has
to file a proposed study plan, and the Commission has to issue a second
scoping document, from 45 days to 30 days after receiving comments (18
CFR 5.10 and 5.11); (2) reduce the time for entities to file comments
on the proposed study plan, from 90 days to 60 days (18 CFR 5.12); (3)
reduce the time an applicant has to file a revised study plan, from 30
days to 15 days (18 CFR 5.13); and (4) reduce the time for filing
comments on an applicant's preliminary licensing proposal, from 90 days
to 60 days (18 CFR 5.16).

iv. License Term Policy
    Section 6 of the FPA provides that hydropower licenses shall be
issued for a term not to exceed 50 years. There is no minimum license
term for original licenses (16 U.S.C. 799). Section 15(e) of the FPA
provides that any new license for an existing project (i.e., relicense)
shall be for a term that the Commission determines to be in the public
interest, but not less than 30 years or more than 50 years (16 U.S.C.
808(e)). Current Commission policy is to set a 30-year license term
where there is little or no authorized redevelopment, new construction,
or environmental mitigation and enhancement; a 40-year license term for
a license involving a moderate amount of these activities; and a 50-
year license term where there is an extensive amount of such
activity.\8\ On November 17, 2016, the Commission issued a notice of
inquiry in FERC Docket No. RM17-4-000 inviting comments on what
changes, if any, should be made to the license term policy. The license
terms provide operational certainty and govern the frequency of the
license renewal process, which influences the overall cost of
development. In turn, shorter license terms could burden development by
increasing the cost of development. The Commission currently is
considering comments on the license term policy, which it could use to
further evaluate the need for any future changes to the license term
policy.
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    \8\ See City of Danville, Virginia, 58 FERC ] 61,318 (1992); and
Consumers Power Co., 68 FERC ] 61,077, (1994).
---------------------------------------------------------------------------

v. Minimum Filing Requirements
    The Commission's regulations contain minimum filing requirements
depending on the size of a project, and whether construction or
modification of a dam is needed for project operation. Part 4 of the
Commission's regulations includes three subparts corresponding to these
factors: (1) Subpart E--Application for License for Major Unconstructed
Project and Major Modified Project (18 CFR 4.40); (2) Subpart F--
Application for License for Major Project--Existing Dam (18 CFR 4.50);
and (3) Subpart G--Application for License for Minor Water Power
Projects and Major Water Power Projects 5 MW or Less (18 CFR 4.60).
Subparts E and F apply to projects greater than 5 MW, and include more
onerous filing requirements than Subpart G, which applies to projects
less than or equal to 5 MW. The 5 MW threshold is based on section 405
of PURPA, which mandated a simplified and expeditious licensing
procedure for small hydroelectric power projects with an installed
capacity of 5 MW or less (see 46 FR 55,944 at 55,947 (1981); 16 U.S.C.
Sec.  2705). The Hydropower Regulatory Efficiency Act of 2013 has since
amended PURPA by increasing the size of a small hydroelectric power
project from 5 to 10 MW. Therefore, the 5 MW threshold in 18 CFR 4.40,
4.50, and 4.60 is materially burdensome to projects between 5 and 10
MW, in terms of the cost and time associated with the more onerous
filing requirements of Subparts E and F. To eliminate the material
burden, the Commission could consider revising its regulations to
increase the threshold from 5 MW.
b. Exemption Processes
i. Increased Capacity Requirement
    To qualify for a license exemption under section 405 of PURPA, an
applicant must propose to install/increase the total capacity of a
project to not more than 10 MW (18 CFR 4.30(b)(31), 4.31(c), and
4.103(a)). The regulatory requirement to add new capacity at the
project is not specifically required by section 405 of PURPA, and it
materially burdens existing licensees that would otherwise be eligible
to seek an exemption at the end of the existing license term. To
eliminate this burden, the Commission could consider revising the
regulations to remove the requirement to install or increase the
capacity of the facility to qualify for an exemption.
ii. Small Hydropower Conversion Restrictions
    In the event that the Commission rejects an exemption application,
the Commission's regulations do not explicitly provide an applicant
with the ability to convert a small hydropower exemption application to
a license application (18 CFR 4.105). The Commission's Handbook for
Hydroelectric Project Licensing and 5 MW Exemptions from Licensing,
issued April 2004, explicitly states at section 6.3.2:
    If the exemption application is dismissed, the process is
terminated. There is no opportunity to convert the exemption
application to an application for license.\9\
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    \9\ See www.ferc.gov/industries/hydropower/gen-info/handbooks/licensing_handbook.pdf.
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    In comparison, the Commission has established a process for
converting a small conduit exemption application to a license
application (18 CFR 4.93). The process for small conduits allows the
applicant to submit additional information necessary to conform the
conduit exemption application to the relevant regulations for a license
application, and then be accepted for filing as of the date the
exemption application was accepted for filing. The inability of an
applicant of a small hydropower exemption to convert its application to
a license application is materially burdensome because the applicant
must initiate an entirely new license process after its exemption is
rejected, thereby causing delay to the development of the resource. To
eliminate this burden, the Commission could consider amending its
regulations to explicitly provide the small hydropower exemption
applicant with the ability to convert its exemption application to a
license application if the exemption application is rejected.
c. Prohibition on Refiling Subsequent License Applications
    Pursuant to the authority provided in section 10(i) of the FPA (16
U.S.C. 803), the Commission routinely waives certain sections of Part I
of the FPA when it issues a minor license. As relevant, the Commission
routinely waives section 15 of the FPA, which governs the Commission's
procedures for issuing a new license to an existing licensee (i.e., a
relicense) (16 U.S.C. and 808). Yet, the Commission's regulations
require the licensee to file an application for relicense at least 24
months before the expiration of the existing license (18 CFR 16.20(c)).
Moreover, if the Commission rejects the application, it cannot be
refiled (18 CFR 16.9(b)(4)). Rejecting a relicense application, and not
providing the applicant with the opportunity to refile, is materially
burdensome to the use of hydropower resources. To eliminate this
burden, the Commission could consider revising its regulations at 18
CFR 16.20 to provide the applicant with the option of resubmitting the
application if the deficiencies are corrected.
2. LNG Facility and Natural Gas Pipeline and Storage Facility Siting
    Under section 7 of the NGA, 15 U.S.C. 717f, the Commission
authorizes the construction, operation, or abandonment of interstate
natural gas pipeline and storage projects, as well as certain types of
LNG facilities (e.g., LNG plants engaged in the storage of interstate
natural gas volumes). Similarly, under section 3 of the NGA, 15 U.S.C.
717b(e)(1), the Commission authorizes the siting, construction and
operation of LNG terminals through which the commodity passes for
export or import. As part of these responsibilities, the Commission
conducts both a non-environmental and

an environmental review of the proposed facilities. The non-
environmental review focuses on the engineering design, rate, and
tariff considerations. The Commission carries out the environmental
review with the cooperation of numerous federal, state, and local
agencies, and with the input of other interested parties. Under the
NGA, the Commission also is the lead federal agency for coordinating
all applicable federal authorizations (e.g., required permits under the
Clean Water Act, Clean Air Act, and Coastal Zone Management Act, among
others) and preparing environmental analyses required under the
National Environmental Policy Act (NEPA) for all interstate natural gas
infrastructure and LNG import/export proposals.
    There are several distinct phases to the review process for
interstate natural gas and LNG facilities under the Commission's
jurisdiction: pre-filing review (if applicable); application review;
and post-authorization compliance. During the pre-filing review,
Commission staff begins work on the environmental review and engages
with stakeholders with the goal of resolving issues before the filing
of an application. Throughout the pre-filing process, Commission staff
meets with stakeholders, visits the project site, and confers with
federal, state, and local agencies.
    Once a project sponsor files an application with the Commission
under NGA section 3 for LNG import/export terminals or under NGA
section 7 for interstate pipeline and storage facilities, Commission
staff analyzes both environmental and non-environmental aspects for a
proposed project, including for LNG terminals safety and engineering.
An Environmental Assessment or Environmental Impact Statement typically
is issued for public comment, and ultimately, the Commission will issue
an order on an application after considering both environmental and
non-environmental issues.
    During the post-authorization compliance period, Commission staff
monitors the project sponsor's compliance with the conditions directed
by the Commission. Ultimately, Commission approval is required before
the facility can begin operation and provide service.
    Pursuant to Executive Order 13783, the review encompassed the
Commission's regulations, guidance documents, and policies related to
the certification of interstate natural gas transportation facilities,
authorization of LNG import and export facilities, authorization of
certain transportation by interstate and intrastate pipelines, and
environmental review under NEPA.
    The majority of agency actions relating to the siting and
construction of interstate natural gas transportation and LNG
facilities do not materially burden the transportation or delivery of
domestically produced natural gas. Specifically, most of the
Commission's actions: (1) Are necessary for the Commission to review
and process NGA section 3 and 7 project applications; and/or (2) do not
negatively affect the siting or construction of natural gas pipeline
and storage facilities or LNG import/export facilities in a manner that
has a direct or primary indirect effect on the development or use of
domestic energy production.
    However, the Commission's regulations require a prospective
applicant for authorization under section 3 of the NGA to site and
construct LNG terminals and related jurisdictional natural gas
facilities to engage in the Commission's pre-filing process. (18 CFR
157.21(a)). The Commission's pre-filing regulations require applicants
to use the pre-filing process for a minimum of 180 days before the
filing of an application for any project that is required to engage in
pre-filing. (18 CFR 157.21(a)(2)(1) and 153.6(c)). While, in general,
the pre-filing process is designed to expedite the processing of
applications, the mandatory imposition of the pre-filing process on LNG
terminals and related pipeline projects for at least 180 days before an
application can be filed may be materially burdensome for some projects
in terms of the potential delay and costs associated with the process.
Although the 180 day pre-filing process is required by statute for LNG
terminals, 15 U.S.C. 717b-1(a), the statute did not mandate that the
Commission also require ``related jurisdictional natural gas
facilities'' to engage in pre-filing. However, related jurisdictional
natural gas pipeline facilities need to be evaluated concurrent with a
proposed LNG terminal to avoid segmentation under the National
Environmental Policy Act. Further, the pre-filing process allows
stakeholders to become involved in the overall Project at an early
stage, and applicants can benefit from stakeholder's early
identification and resolution of issues that may overlap with the LNG
terminal. Without using the pre-filing process for related
jurisdictional natural gas facilities, delays could occur during the
application review, when issues are first identified and need
resolution. Thus, although this regulation may result in delays or
additional costs to the applicant early on in a project's development,
its overall result is a more timely application review by considering
all issues regarding a project concurrently. As such, there is no need
for the Commission to consider any revision to this regulation.
3. Centralized Electric Capacity Market Policies
    Three of the Regional Transmission Operator/Independent System
Operator (RTO/ISO) markets in the eastern U.S. have adopted centralized
capacity markets to help address resource adequacy concerns.\10\ In
particular, PJM, ISO-NE, and NYISO have implemented centralized
capacity markets that were designed, in part, to ensure long-term
resource adequacy by sending accurate price signals for investment in
capacity resources, when and where needed.\11\ As a result, agency
actions related to capacity market policies could have a primary
indirect effect on the development and use of generation resources,
including renewables, natural gas, and nuclear facilities.\12\
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    \10\ The Commission has defined resource adequacy as ``the
availability of an adequate supply of generation or demand
responsive resources to support safe and reliable operation of the
grid.'' Cal. Indep. Sys. Operator Corp., 122 FERC ] 61,017, at P 3
(2008).
    \11\ ``Capacity is not actual electricity. It is a commitment to
produce electricity or forgo consumption of electricity when
required.'' Advanced Energy Mgmt. All. v. FERC, No. 16-1234, 2017 WL
2636455, at *1 (D.C. Cir. Jun. 20, 2017); see Conn. Dep't of Pub.
Util. Control v. FERC, 569 F.3d 477, 482 (D.C. Cir. 2009)
(explaining that capacity ``amounts to a kind of call option that
electricity transmitters purchase from parties--generally,
generators--who can either produce more or consumer less when
required'').
    \12\ It is important to note that the Commission has not
required RTOs/ISOs to implement centralized capacity markets;
rather, the determination to include such markets has been a
voluntary decision by the stakeholders in each particular RTO/ISO.
However, once an RTO/ISO decides to implement such a capacity
market, the Commission must ensure that the tariff provisions
establishing the capacity market rules are just and reasonable and
not unduly discriminatory or preferential.
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    The centralized capacity markets require load-serving entities to
secure, either through self-supply \13\ or participation in the
capacity auction, sufficient resources to meet their capacity
obligation at a future time. All three centralized capacity markets
allow participation by any resource that is technically qualified to
provide the capacity product being procured and each market generally
models locational constraints. Each conducts a capacity auction where
eligible offers to sell capacity are compared to the demand for
capacity resources, which is established through an administratively-

determined demand curve. Generally speaking, the market clears based on
the intersection between the supply and demand curves. All cleared
resources receive the market clearing price for capacity regardless of
resource type.
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    \13\ While the specific rules vary by RTO/ISO, load-serving
entities can own or construct resources or contract bilaterally for
capacity from resources owned by other entities.
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    The Commission has issued multiple agency actions (i.e., Commission
orders addressing the capacity market designs of the relevant organized
markets) that govern the rules and design of the centralized capacity
markets. Agency actions related to electric capacity markets were
reviewed to determine if they impose a material burden on the
development and use of domestic energy resources. In general, agency
actions regarding centralized electricity capacity market design do not
impose a material burden on the development and use of domestic energy
resources because they generally seek to ensure adequate resources, and
thereby facilitate the development of domestic energy resources, rather
than create material burdens to the development and use of these
resources. However, this final report discusses Commission actions
regarding one aspect of centralized electricity capacity markets,
buyer-side market power mitigation rules, due to the potentially
material burdens Commission actions may have on the development of
domestic energy resources.
    All three eastern RTOs/ISOs use some form of a minimum offer price
rule (MOPR) as approved by Commission order. MOPRs as currently
designed establish offer floors for certain new resources to protect
against subsidized new entry that has the potential to artificially
suppress capacity market prices. New resources that trigger this rule
are required to submit offers into the capacity market auction at or
above the floor. If the resource's mitigated offer price is too high to
clear in the market, then the resource would not receive a capacity
obligation and the associated market payments. Depending on the terms
of any out-of-market contracts, the resource also may not be eligible
to receive out-of-market payments if it does not clear in the capacity
market auction. Without such compensation, the developer may conclude
it is not economic to develop the resource. In this way, Commission
actions on the MOPR arguably impose a burden on certain new resources.
    However, Commission actions on the MOPR do not rise to the level of
a material burden, as the term is defined in the Executive Order and
Guidance Memo. While application of the MOPR to a generator's bid may
conceivably result in the developer deciding not to develop its
generation resource, an individual generation developer's decision not
to develop as a result of being subject to a MOPR would not in and of
itself materially affect the use or development of oil, natural gas,
coal, nuclear energy, or other domestic energy resources in the U.S.
Therefore, Commission actions on MOPRs do not negatively affect the
development and use of domestic energy resources by the electricity
sector, despite the potential burden on those individual resources that
are mitigated. Furthermore, from the perspective of other resources in
the market, the MOPR can help preserve the integrity of the market
price signals and revenue streams, thereby facilitating development and
retention of other resources that might use domestic energy resources.
4. Generator Interconnection Policies
    Electric generators use domestic energy resources to produce
electricity. Electric generators at utility scale must interconnect to
the transmission system to deliver the electricity they produce to
customers and receive benefits from the wholesale electric markets. The
interconnection process is designed to ensure a new resource can safely
and reliably deliver its output to end-users and to assign the costs to
the party causing the costs of any system upgrades required to maintain
safety and reliability. If a generator is not able to interconnect to
the transmission system, or if it is too difficult or expensive to do
so, the developer may decide not to pursue investment in the electric
generation resource. Therefore, the ability of an electric generator to
interconnect to a transmission system could affect the development or
use of domestic energy resources.
    The Commission has issued multiple agency actions that govern and
facilitate the interconnection of electric generators to public utility
transmission systems. They include:
    Order No. 2003: In Order No. 2003, the Commission created standard
large generator interconnection procedures and adopted a standard large
generator interconnection agreement for the interconnection of electric
generators larger than 20 MW, regardless of resource type.\14\
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    \14\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
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    Order No. 2006: In Order No. 2006, the Commission created standard
small generator interconnection procedures and a standard small
generator interconnection agreement for the interconnection of electric
generators no larger than 20 MW.\15\
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    \15\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order granting clarification, Order No. 2006-B, FERC
Stats. & Regs. ] 31,221 (2006).
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    Order No. 661: In Order No. 661, the Commission required public
utilities to add standard procedures and technical requirements for the
interconnection of large wind generation resources to their standard
large generator interconnection procedures and large generator
interconnection agreements in their open access transmission
tariffs.\16\
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    \16\ Interconnection for Wind Energy, Order No. 661, FERC Stats.
& Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. &
Regs. ] 31,198 (2005).
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    Order No. 827: In Order No. 827, the Commission revised the
interconnection agreements for both large and small non-synchronous
generators to eliminate exemptions for wind generators from providing
reactive power.\17\
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    \17\ Reactive Power Requirements for Non-Synchronous Generators,
Order No. 827, FERC Stats. & Regs. ] 31,385, order on reh'g, 157
FERC ] 61,003 (2016).
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    Order No. 828: In Order No. 828, the Commission modified the small
generator interconnection agreement as set forth in Order Nos. 2006 and
792 to require newly interconnecting small generating facilities to
ride through abnormal frequency and voltage events and not disconnect
during such events.\18\
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    \18\ Requirements for Frequency and Voltage Ride Through
Capability of Small Generating Facilities, Order No. 828, 156 FERC ]
61,062 (2016).
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    Order No. 792: In Order No. 792, the Commission revised the
standard small generator interconnection procedures and standard small
generator interconnection agreement for the interconnection of electric
generators no larger than 20 MW.\19\
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    \19\ Small Generator Interconnection Agreements and Procedures,
Order No. 792, 145 FERC ] 61,159 (2013), clarifying, Order No. 792-
A, 146 FERC ] 61,214 (2014).
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    None of these orders materially burden the development or use of
domestic energy resources. The Commission's generator interconnection
orders establish an orderly, uniform process for all types of
generators to interconnect to the grid safely and reliably,
facilitating their development by providing them with the means to
deliver the electricity they produce to the purchaser. As such, these
requirements will not unnecessarily obstruct, delay, curtail or
otherwise

impose significant costs on the siting, permitting, production,
utilization, transmission, or delivery of energy resources and
therefore they will not materially burden the production or use of
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domestic energy resources.

    Dated: October 25, 2017.
Kimberly D. Bose,
Secretary.
[FR Doc. 2017-23722 Filed 10-31-17; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 83, Number 34 (Tuesday, February 20, 2018)]
[Notices]
[Pages 7278-7279]
[FR Doc No: 2018-03467]

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SECURITIES AND EXCHANGE COMMISSION

Sunshine Act Meetings

TIME AND DATE: Notice is hereby given, pursuant to the provisions of
the Government in the Sunshine Act, Public Law 94-409, the Securities
and Exchange Commission will hold an Open Meeting on Wednesday,
February 21, 2018 at 10:00 a.m.

PLACE: The meeting will be held in Auditorium LL-002 at the
Commission's headquarters, 100 F Street NE, Washington, DC 20549.

STATUS: This meeting will begin at 10:00 a.m. (ET) and will be open to
the public. Seating will be on a first-come, first-served basis.
Visitors will be subject to security checks. The meeting will be
webcast on the Commission's website at www.sec.gov.

MATTERS TO BE CONSIDERED: The subject matters of the Open Meeting will
be the Commission's consideration of:
     Whether to approve the issuance of an interpretive release
to provide guidance to assist public companies in preparing disclosures
about cybersecurity risks and incidents.
     whether to adopt an interim final rule revising the
compliance date for certain provisions of rule 22e-4 under the
Investment Company Act of 1940 and related reporting and disclosure
requirements.
     whether to propose amendments to Form N-PORT and Form N-1A
related to disclosures of liquidity risk management for open end
management investment companies.
    At times, changes in Commission priorities require alterations in
the scheduling of meeting items.

CONTACT PERSON FOR MORE INFORMATION: For further information and to
ascertain what, if any, matters have been added, deleted or postponed;
please contact Brent J. Fields from the Office of the Secretary at
(202) 551-5400.

    Dated: February 14, 2018.
Brent J. Fields,
Secretary.
[FR Doc. 2018-03467 Filed 2-15-18; 11:15 am]
BILLING CODE 8011-01-P