924,574

Subtotal
                                      124
                                                                     -8,495,763
                                                                        -68,514
                                                                        -15,463
                                                                       -847,055
                                                                        924,574
Pipeline

Small
                                      11
                                                                          3,629
                                                                            330
                                                                            119
                                                                             19
                                                                          1,226

Large
                                      36
                                                                      1,593,661
                                                                         44,268
                                                                          4,095
                                                                             40
                                                                        965,348

Subtotal
                                      47
                                                                      1,597,289
                                                                         33,985
                                                                          2,425
                                                                             19
                                                                        965,348
Processing

Small
                                      39
                                                                        349,635
                                                                          8,965
                                                                          1,382
                                                                            138
                                                                        202,911

Large
                                      23
                                                                        631,112
                                                                         27,440
                                                                          5,971
                                                                             28
                                                                        311,071

Subtotal
                                      62
                                                                        980,747
                                                                         15,819
                                                                          2,004
                                                                             28
                                                                        311,071
Pipelines/Processing

Small
                                       0
                                                                            ---
                                                                            ---
                                                                            ---
                                                                            ---
                                                                            ---

Large
                                      13
                                                                      5,198,212
                                                                        399,862
                                                                        143,446
                                                                          1,511
                                                                      2,777,165

Subtotal
                                      13
                                                                      5,198,212
                                                                        399,862
                                                                        143,446
                                                                          1,511
                                                                      2,777,165
Total

Small
                                      127
                                                                     -1,577,407
                                                                        -12,421
                                                                           -902
                                                                       -255,773
                                                                        202,911

Large
                                      119
                                                                        857,892
                                                                          7,209
                                                                          2,419
                                                                       -847,055
                                                                      2,777,165

Total
                                      246
                                                                       -719,514
                                                                         -2,925
                                                                            103
                                                                       -847,055
                                                                      2,777,165

Table 7-23	Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by Final NSPS

                                Number of Firms
Descriptive Statistics for Sales Test Ratio Without Estimated Revenues from Natural Gas Product Recovery (%)
Firm Type/Size

                                    Average
                                    Median
                                    Minimum
                                    Maximum
Production and Integrated

Small
                                      77
                                                                          0.97%
                                                                          0.22%
                                                                          0.01%
                                                                         23.17%

Large
                                      47
                                                                          0.19%
                                                                          0.14%
                                                                          0.00%
                                                                          1.28%

Subtotal
                                      124
                                                                          0.67%
                                                                          0.18%
                                                                          0.00%
                                                                         23.17%
Pipeline

Small
                                      11
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%

Large
                                      36
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.06%

Subtotal
                                      47
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.06%
Processing

Small
                                      39
                                                                          0.02%
                                                                          0.01%
                                                                          0.00%
                                                                          0.15%

Large
                                      23
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.16%

Subtotal
                                      62
                                                                          0.02%
                                                                          0.01%
                                                                          0.00%
                                                                          0.16%
Pipelines/Processing

Small
                                       0
                                                                            ---
                                                                            ---
                                                                            ---
                                                                            ---

Large
                                      13
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%

Subtotal
                                      13
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%
Total

Small
                                      127
                                                                          0.59%
                                                                          0.07%
                                                                          0.00%
                                                                         23.17%

Large
                                      119
                                                                          0.08%
                                                                          0.00%
                                                                          0.00%
                                                                          1.28%

Total
                                      246
                                                                          0.35%
                                                                          0.02%
                                                                          0.00%
                                                                         23.17%

	The mean cost-sales ratio for all businesses when estimated product recovery is excluded from the analysis of the sample data is 0.35 percent, with a median ratio of 0.02 percent, a minimum of less than 0.01 percent, and a maximum of over 23 percent (Table 7-23).  For small firms in the sample, the mean and median cost-sales ratios are 0.59percent and 0.07 percent, respectively, with a minimum of less than 0.01 percent and a maximum of over 23 percent (Table 7-23).  Each of these statistics indicates that, when considered in the aggregate, impacts are relatively higher on small firms than large firms when the estimated revenue from additional natural gas product recovery is excluded.  However, as the next table shows, the reverse is true when these revenues are included.
Table 7-24	Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for Firms Affected by Final NSPS

                                Number of Firms
Descriptive Statistics for Sales Test Ratio With Estimated Revenues from Natural Gas Product Recovery (%)
Firm Type/Size

                                    Average
                                    Median
                                    Minimum
                                    Maximum
Production and Integrated

Small
                                      77
                                                                         -0.05%
                                                                         -0.01%
                                                                         -1.06%
                                                                          0.01%

Large
                                      47
                                                                         -0.01%
                                                                         -0.01%
                                                                         -0.07%
                                                                          0.14%

Subtotal
                                      124
                                                                         -0.03%
                                                                         -0.01%
                                                                         -1.06%
                                                                          0.14%
Pipeline

Small
                                      11
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%

Large
                                      36
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.06%

Subtotal
                                      47
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.06%
Processing

Small
                                      39
                                                                          0.01%
                                                                          0.01%
                                                                          0.00%
                                                                          0.11%

Large
                                      23
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.11%

Subtotal
                                      62
                                                                          0.01%
                                                                          0.00%
                                                                          0.00%
                                                                          0.11%
Pipelines/Processing

Small
                                       0
                                                                            ---
                                                                            ---
                                                                            ---
                                                                            ---

Large
                                      13
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%

Subtotal
                                      13
                                                                          0.00%
                                                                          0.00%
                                                                          0.00%
                                                                          0.01%
Total

Small
                                      127
                                                                         -0.03%
                                                                          0.00%
                                                                         -1.06%
                                                                          0.11%

Large
                                      119
                                                                          0.00%
                                                                          0.00%
                                                                         -0.07%
                                                                          0.14%

Total
                                      246
                                                                         -0.01%
                                                                          0.00%
                                                                         -1.06%
                                                                          0.14%

	The mean cost-sales ratio for all businesses when estimated product recovery is included is in the sample is -0.01 percent, with a median ratio of less than 0.01 percent, a minimum of       -1.06 percent, and a maximum of 0.14 percent (Table 7-24).  For small firms in the sample, the mean and median cost-sales ratios are -0.03 percent and less than 0.01 percent, respectively, with a minimum of -1.06 percent and a maximum of 0.11 percent (Table 7-24).  Each of these statistics indicates that, when considered in the aggregate, impacts are small on small business when the estimated revenue from additional natural gas product recovery are included, the reverse of the conclusion found when these revenues are excluded.
Meanwhile, Table 7-25 presents the distribution of estimated cost-sales ratios for the small firms in our sample with and without including estimates of the expected natural gas product recover from implementing controls.  When revenues estimates are included, all 127 firms (100 percent) have estimated cost-sales ratios less than 1 percent. While less than 1 percent, the highest cost-sales ratios for small firms in the sample experiencing impacts are largely driven by costs accruing to processing and pipeline firms.  That said, the incremental costs imposed on firms that process natural gas or transport natural gas via pipelines are not estimated to create significant impacts on a cost-sales ratio basis at the firm-level.
Table 7-25	Impact Levels of Final NSPS on Small Firms as a Percent of Small Firms in Sample, With and Without Revenues from Additional Natural Gas Product Recovery

         Without Estimated Revenues from Natural Gas Product Recovery
           With Estimated Revenues from Natural Gas Product Recovery
                                 Impact Level
           Number of Small Firms in Sample Estimated to be Affected
              % of Small Firms in Sample Estimated to be Affected
           Number of Small Firms in Sample Estimated to be Affected
              % of Small Firms in Sample Estimated to be Affected
C/S Ratio less than 1%
                                     120
                                     94.5%
                                      127
                                    100.00%
C/S Ratio 1-3%
                                       4
                                     3.1%
                                       0
                                     0.00%
CS Ratio greater than 3%
                                       3
                                     2.4%
                                       0
                                     0.00%

When the estimated revenues from product recovery are not included in the analysis, four firms (about 3 percent) are estimated to have sales test ratios between 1 and 3 percent.  Three firms (about 2 percent) are estimated to have sales test ratios greater than 3 percent.  These results noted, the exclusion of product recovery is somewhat artificial.  While the mean engineering compliance costs and revenues estimates are valid, drawing on the means ignores the distribution around the mean estimates, which risks masking effects.  Because of this risk, the following section offers a qualitative discussion of small entities with regard to obtaining REC services, the validity of the cost and performance of RECs for small firms, as well as offers a discussion about whether older equipment, which may be disproportionately owned and operated be smaller producers, would be affected by the final NSPS.

Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion
<IP_ADDRESS>.1 	Small Entities and Reduced Emissions Completions
      Because REC requirements of the final NSPS are expected to contribute the large majority of engineering compliance costs, it is important to examine these requirements more closely in the context small entities.  Important issues to resolve are the scale of REC costs within a drilling project, how the payment system for recovered natural gas functions, whether small entities pursue particular "niche" strategies that may influence the costs or performance in a way that makes the estimates costs and revenues invalid.
      According to the most recent natural gas well cost data from EIA, the average cost of drilling and completing a producing natural gas well in 2007 was about $4.8 million (adjusted to 2008 dollars).  This average includes lower cost wells that may be relatively shallow or are not hydraulically fractured.  Hydraulically fractured wells in deep formations may cost up to $10 million.  RECs contracted from a service provider are estimated to cost $33,200 (in 2008 dollars) or roughly 0.3%-0.7% of the typical cost of a drilling and completing a natural gas well.  As this range does not include revenues expected from natural gas and hydrocarbon condensate recovery expected to offset REC implementation costs, REC costs likely represent a small increment of the overall burden of a drilling project.
      To implement an REC, a service provider, which may itself be a small entity, is typically contracted to bring a set of equipment to the well pad temporarily to capture the stream that would otherwise be vented to the atmosphere.  Typically, service providers are engaged in a long term drilling program in a particular basin covering multiple wells on multiple well pads.  For gas captured and sold to the gathering system, Lease Automatic Custody Transfer (LACT) meters are normally read daily automatically, and sales transactions are typically settled at the end of the month.  Invoices from service providers are generally delivered in 30-day increments during the well development time period, as well as at the end of the working contract for that well pad.  The conclusion from the information, based on the available information, in most cases, the owner/operator incurs the REC cost within the same 30 day period that the owner/operator receives revenue as a result of the REC.
      We assume small firms are performing RECs in CO and WY, as in many instances RECs are required under state regulation.  In addition to State regulations, some companies are implementing RECs voluntarily such as through participation in the EPA Natural Gas STAR Program and the focus of recent press reports.
      As described in more detail below, many small independent E&P companies often do not conduct any of the actual field work.  These firms will typically contract the drilling, completion, testing, well design, environmental assessment, and maintenance.  Therefore, we believe it is likely that small independent E&P firms will contract for RECs from service providers if required to perform RECs.  An important reminder is that performing a REC is a straightforward and inexpensive extension of drilling, completion, and testing activities.
      To the extent that very small firms may specialize in operating relatively few low-producing stripper wells, it is important to ask whether low-producing wells are likely candidates for re-fracturing/re-completion and, if so, whether the expected costs and revenues would be valid.  These marginal gas wells are likely to be older and in conventional formations, and as such are unlikely to be good candidates for re-fracturing/completion.  To the extent the marginal wells may be good candidates for re-fracturing/completion, the REC costs are valid estimates.  The average REC cost is valid for RECs performed on any well, regardless of the operator size.  The reason for this is that the REC service is contracted out to specialty service providers who charge daily rates for the REC equipment and workers.  The cost is not related to any well characteristic.
      Large operators may receive a discount for offering larger contracts which help a service provider guarantee that REC equipment will be utilized.  However, we should note that the existence of a potential discount for larger contracts is based on a strong assumption; we do not have evidence to support this assumption.  Since contracting REC equipment is analogous to contracting for drilling equipment, completion equipment, etc., the premium would likely be in the same range as other equipment contracted by small operators.  Since the REC cost is a small portion of the overall well drilling and completion cost, the effect of any bulk discount disparity between large and small operators will be small, if in fact it does exist.
      Although small operators may own the majority of marginal and stripper wells, they will make decisions based on economics just as any sized company would.  For developing a new well, any sized company will expect a return on their investment meaning the potential for sufficient gas, condensate, and/or oil production to pay back their investment and generate a return that exceeds alternative investment opportunities.  Therefore, small or large operators that are performing hydraulic fracture completions will experience the same distribution of REC performance.  For refracturing an existing well, the well must be a good candidate to respond to the re-fracture/completion with a production increase that merits the investment in the re-fracture/completion.
      Plugging and abandoning wells is complex and costly, so sustaining the productivity of wells is important for maximizing the exploitation of proven domestic resources.  However, many marginal gas wells are likely to be older and in conventional formations, and as such are unlikely to be good candidates for re-fracturing/completion, which means they are likely unaffected by the final NSPS.
<IP_ADDRESS>.2 	Age of Equipment and Final Regulations
Given a large fraction of domestic oil and natural gas production is produced from older and generally low productivity wells, it is important to examine whether the requirements of these rules might present impediments to owners and operators of older equipment.  The NSPS is a standard that applies to new or modified sources.  Because of this, NSPS requirements target new or modified affected facilities or equipment, such as processing plants and compressors.  While the requirements may apply to modifications of existing facilities, it is important to discuss well completion-related requirements aside from other requirements in the NSPS distinctly.
Excluding well completion requirements from the cost estimates, the non-completion NSPS requirements (related to equipment leaks at processing plants, reciprocating and centrifugal compressors, pneumatic controllers, and storage vessels) are estimated to require about $15 million in annualized engineering costs.  EPA also estimates that the annualized costs of these requirements will be mostly if not fully offset by revenues expected from natural gas recovery.  EPA does not expect these requirements to disproportionately affect producers with older equipment.  Meanwhile, the REC and emissions combustion requirements in the final NSPS relate to well completion activities at new hydraulically fractured natural gas wells and existing wells which are recompleted after being fractured or re-fractured.  These requirements constitute the bulk of the expected engineering compliance expenditures (about $320 million in annualized costs) and expected revenues from natural gas product recovery (about $330 million in revenues, annually).
While age of the well and equipment may be an important factor for small and large producers in determining whether it is economical to fracture or re-fracture an existing well, this equipment is unlikely to be subject to the NSPS.  To comply with completion-related requirements, producers are likely to rely heavily on portable and temporary completion equipment brought to the wellpad over a short period of time (a few days to a few weeks) to capture and combust emissions that are otherwise vented.  The equipment at the wellhead -- newly installed in the case of new well completions or already in place and operating in the case of existing wells -- is not likely to be subject to the NSPS requirement.
Small Entity Economic Impact Analysis, Final NESHAP Amendments
The Final NESHAP Amendments will affect facilities operating three types of equipment: glycol dehydrators at production facilities, glycol dehydrators at transmission and compression facilities, and storage vessels.  We identified likely affected facilities in the National Emissions Inventory (NEI) and estimated the number of newly required controls of each type that would be required by the NESHAP Amendments for each facility.  We then used available data sources to best identify the ultimate owner of the equipment that would likely require new controls and linked facility-level compliance cost estimates to firm-level employment and revenue data.  These data were then used to calculate an estimated compliance costs to revenues ratio to identify small businesses that might be significantly impacted by the NESHAP.
While we were able to identify the owners all but 14 facilities likely to be affected, we could not obtain employment and revenue levels for all of these firms.  Overall, we expect about 381 facilities to be affected, and these facilities are owned by an estimated 155 firms.  We were unable to obtain financial information on 47 (30 percent) of these firms due to inadequate data.  In some instances, firms are private, and financial data is not available.  In other instance, firms may no longer exist, since NEI data are not updated continuously.  From the ownership information and compliance cost estimates from the engineering analysis, we estimated total compliance cost per firm.
Of the 108 firms for which we have financial information, we identified 54 small firms and 54 large firms that would be affected by the NESHAP Amendments.  Annual compliance costs for small firms are estimated at $2.6 million (17 percent of the total compliance costs), and annual compliance costs for large firms are estimated at $10 million (66 percent of the total compliance costs).  The facilities for which we were unable to identify the ultimate owners, employment, and revenue levels would have an estimated annual compliance cost of $2.6 million (17percent of the total).  All figures are in 2008 dollars.
The average estimated annualized compliance cost for the 54 small firms identified in the dataset is $48,000, while the mean annual revenue figure for the same firms is over $109 million, or less than 1 percent for a average sales-test ratio for all 54 firms (Table 7-26).  The median sale-test ratio for these firms is smaller at 0.17 percent.  Large firms are likely to see an average of $183,000 in annual compliance costs, whereas average revenue for these firms exceeds $30 billion since this set of firms includes many of the very large, integrated energy firms.  For large firms, the average sales-test ratio is about 0.01 percent, and the median sales-test ratio is less than 0.01 percent (Table 7-26).
Table 7-26	Summary of Sales Test Ratios for Firms Affected by Final NESHAP Amendments
                                   Firm Size
                          No. of Known Affected Firms
                        % of Total Known Affected Firms
                                Mean C/S Ratio
                               Median C/S Ratio
                                Min. C/S Ratio
                                Max. C/S Ratio
Small
                                      54
                                      50%
                                     0.72%
                                     0.17%
                                  < 0.01%
                                     8.5%
Large
                                      54
                                      50%
                                     0.01%
                                  < 0.01%
                                  < 0.01%
                                     0.3%
All
                                      108
                                     100%
                                     0.37%
                                     0.02%
                                  < 0.01%
                                     8.5%

      Among the small firms, 45 of the 54 (83 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues.  Meanwhile nine firms (17 percent) are likely to have impacts greater than 1 percent (Table 7-27).  Three of these nine firms are likely to have impacts greater than 3 percent (Table 7-27) While these nine firms might receive significant impacts from the final NESHAP Amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211 (Table 7-27).

Table 7-27	Affected Small Firms as a Percent of Small Firms Nationwide, Final NESHAP Amendments
                                   Firm Size
                  Number of Small Firms Affected Nationwide
                     % of Small Firms Affected Nationwide
                Affected Firms as a % of National Firms (6,427)
C/S Ratio less than 1%
                                      45
                                     83.3%
                                     0.70%
C/S Ratio 1-3%
                                       6
                                     11.1%
                                     0.09%
CS Ratio greater than 3%
                                       3
                                     5.6%
                                     0.05%

Conclusions for NSPS and NESHAP Amendments
While both the NSPS and NESHAP amendment would individually result in a no SISNOSE finding, the EPA performed an additional analysis in order to certify the rule in its entirety. This analysis compared compliance costs to entity revenues for the total of all the entities affected by the NESHAP Amendments and the sample of entities analyzed for the NSPS. When revenues from additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues (Table 7-28). Meanwhile, 16 firms (9 percent) are likely to have impacts greater than 1 percent. Six of these 16 firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales are included, 160 small firms (95 percent) are likely to have impacts of less than 1 percent. Nine firms (5 percent) are likely to have impacts greater than 1 percent, while only three of these nine are likely to have impacts greater than 3 percent.
Table 7-28	Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS and NESHAP Amendments

         Without Estimated Revenues from Natural Gas Product Recovery
           With Estimated Revenues from Natural Gas Product Recovery
                                 Impact Level
           Number of Small Firms in Sample Estimated to be Affected
              % of Small Firms in Sample Estimated to be Affected
           Number of Small Firms in Sample Estimated to be Affected
              % of Small Firms in Sample Estimated to be Affected
C/S Ratio less than 1%
                                     153
                                     90.5%
                                      160
                                     94.7%
C/S Ratio 1-3%
                                      10
                                     5.9%
                                       6
                                     3.6%
CS Ratio greater than 3%
                                       6
                                     3.6%
                                       3
                                     1.8%

The number of significantly impacted small businesses is unlikely to be sufficiently large to declare a SISNOSE.   Our judgment in this determination is informed by the fact that many affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered by the implementation of the controls evaluated in this RIA.  As much of the additional natural gas recovery is estimated to arise from completion-related activities, we expect the impact on well-related compliance costs to be significantly mitigated. This conclusion is enhanced because the returns to reduced emissions completion activities occur without a significant time lag between implementing the control and obtaining the recovered product unlike many control options where the emissions reductions accumulate over long periods of time; the reduced emission completions and recompletions occur over a short span of time, during which the additional product recovery is also accomplished.
References

Bezdek, R.H., R.M. Wendling, and P. DiPerna. 2008. "Environmental protection, the economy,
and jobs: national and regional analyses." Journal of Environmental Management
86(1):63-79.

Duda, J.R., G. Covatch, D. Remson, S. Wang. 2005. Projections of marginal wells and their contributions to oil and natural gas supplies. Society of Petroleum Engineers Eastern regional Meeting, SPE98014.

Gabriel, S.A., A.S. Kydes, and P. Whitman. 2001. "The National Energy Modeling System: a large-scale energy-economic equilibrium model." Operations Research 49:1: 14-25.

IHS Global Insight. "The Economic Contribution of the Onshore Independent oil and Natural Gas Producers to the U.S. Economy."  Prepared for the Independent Petroleum Association of America.  April 2011.  <http://www.ipaa.org/news/docs/IHSFinalReport.pdf> Accessed July 23, 2011.
Morgenstern, R.D. W.A. Pizer, and J. Shih. 2002. "Jobs versus the environment: an industry-level perspective," Journal of Environmental Economics and Management 43(3):412-436.
Oil and Gas Journal. "Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow." November 1, 2010.

Oil and Gas Journal. "OGJ150." September 21, 2009.

Oil and Gas Journal. "OGJ150 Financial Results Down in '09; Production, Reserves Up." September 6, 2010.

Oil and Gas Journal. "Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009." June 7, 2010.

U.S. Small Business Administration (U.S. SBA), Office of Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President's Small Business Agenda and Executive Order 13272.

U.S. Energy Information Administration (U.S. EIA). 2010. Documentation of the Oil and Gas Supply Module (OGSM). May 2010. DOE/EIA-M06(2010). <http://www.eia.gov/FTPROOT/modeldoc/m063(2010).pdf>  Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2010.  Model Documentation Natural Gas Transmission and Distribution Module of the National Energy Modeling System. June 2010.  DOE/EIA-M062(2010)  <http://www.eia.gov/FTPROOT/modeldoc/m062(2010).pdf> Accessed March 30, 2011.


[Federal Register Volume 80, Number 54 (Friday, March 20, 2015)]
[Rules and Regulations]
[Pages 14808-14810]
[FR Doc No: 2015-06053]

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

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2014-1093; Directorate Identifier 2014-CE-035-AD;
Amendment 39-18119; AD 2015-06-01]
RIN 2120-AA64

Airworthiness Directives; British Aerospace Regional Aircraft
Airplanes

AGENCY: Federal Aviation Administration (FAA), Department of
Transportation (DOT).

ACTION: Final rule.

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

SUMMARY: We are superseding an airworthiness directive (AD) 2014-06-03
for British Aerospace Regional Aircraft Model Jetstream Series 3101 and
Jetstream Model 3201 airplanes. This AD results from mandatory
continuing airworthiness information (MCAI) issued by an aviation
authority of another country to identify and correct an unsafe
condition on an aviation product. The MCAI describes the unsafe
condition as stress corrosion cracking of the main landing gear spigot
housing. We are issuing this AD to require actions to address the
unsafe condition on these products.

DATES: This AD is effective April 24, 2015.
    The Director of the Federal Register approved the incorporation by
reference of certain publications listed in the AD as of April 24,
2015.

ADDRESSES: You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2014-
1093; or in person at the Docket Management Facility, U.S. Department
of Transportation, Docket Operations, M-30, West Building Ground Floor,
Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590.
    For service information identified in this AD, contact BAE Systems
(Operations) Ltd, Customer Information Department, Prestwick
International Airport, Ayrshire, KA9 2RW, Scotland, United Kingdom;
phone: +44 1292 675207, fax: +44 1292 675704; email:
<EMAIL_ADDRESS>Internet: http://www.jetstreamcentral.com. You may view this referenced service
information at the FAA, Small Airplane Directorate, 901 Locust, Kansas
City, Missouri 64106. For information on the availability of this
material at the FAA, call<PHONE_NUMBER>. It is also available on the
Internet at http://www.regulations.gov by searching for locating Docket
No. FAA-2014-1093.

FOR FURTHER INFORMATION CONTACT: Taylor Martin, Aerospace Engineer, 901
Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329-
4138; fax:<PHONE_NUMBER>; email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Discussion

    We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR
part 39 to add an AD that would apply to British Aerospace Regional
Aircraft Model Jetstream Series 3101 and Jetstream Model 3201
airplanes. That NPRM was published in the Federal Register on December
31, 2014 (79 FR 78726), and proposed to supersede AD 2014-06-03,
Amendment 39-17807 (79 FR 17395, March 28, 2014).
    The NPRM proposed to correct an unsafe condition for the specified
products and was based on mandatory continuing airworthiness
information (MCAI) originated by an aviation authority of another
country. The MCAI states that:

    Several cases of stress corrosion cracking of DTD 5094 standard
Main Landing Gear (MLG) cylinders have been reported on Jetstream
Series 3200 and 3100 aeroplanes.
    Prompted by these findings, The United Kingdom (UK) Civil
Aviation Authority (CAA) issued AD 003-01-86 to require visual and
non-destructive testing (NDT) inspections of the MLG assembly
cylinder attachment spigot housing in accordance with BAE Systems
(Operations) Ltd SB 32-A-JA851226. In 2012 an additional occurrence
of Jetstream 3100 MLG failure after landing was reported, the
subsequent investigation revealed stress corrosion cracking of the
yoke pintle housing as a root cause of the MLG failure. Consequently
EASA issued EASA AD 2013-0208 to require inspection of the MLG in
accordance with BAE Systems (Operations) Ltd SB 32-A-JA851226
Revision 5 or later approved revisions to detect any crack, however,
SB 32-A-JA851226 did not apply to aeroplanes equipped with MLG
cylinders manufactured from L161 material, since that is not
susceptible to stress corrosion, BAE Systems (Operations) Ltd issued
SB 32-JM7862 to address degradation of the surface protection by
placing a special washer over the forward face of the MLG spigot
housing, which rotates with the spigot housing. EASA issued AD 2013-
0206 to require modification of the left (LH) and right hand (RH)
MLG in accordance with this SB.
    In 2014 a further event was reported, where the LH MLG of a
Jetstream 3100 aeroplane collapsed during landing, this resulted in
the aeroplane departing from the runway. The accident is still under
investigation by the UK Air Accident Investigation Branch.
Preliminary results of the investigation determined that cracking,
which caused the MLG collapse, was initiated from a corrosion pit at
the top outer edge of the forward spigot housing and extended along
the top of the spigot housing. The spigot housing material was DTD
5094. The affected LH MLG had been modified in accordance with BAE
Systems (Operations) Ltd SB 32-JM7862 Revision 1. Further
investigation discovered that the instructions provided in BAE
Systems (Operations) Ltd SB 32-JM7862 Revision 1 did not effectively
prevent stress corrosion cracking because, under certain
circumstances, it allows the rotation of the special washer and
consequent damage of the end face of the spigot housing.
    This condition, if not corrected, could lead to structural
failure of the MLG, possibly resulting in loss of control of the
aeroplane during take-off or landing runs.
    To address this potential unsafe condition, BAE Systems
(Operations) Ltd issued SB 32-JM7862 Revision 2 to clarify the
orientation of the spigot bearing cap, later revised to SB 32-JM7862
Revision 3 to ensure the spigot bearing cap is correctly positioned.
Additionally, BAE Systems (Operations) Ltd issued SB 32-A-JA140940
to provide inspection instructions to detect migration of the
special washer and any potential corrosion resulting from that
unwanted migration for MLG installations modified earlier in
accordance with BAE Systems (Operations) Ltd SB 32-JM7862 up to
Revision 2.
    For the reasons described above, this AD partially retains the
requirements of EASA AD 2013-0206, which is superseded, and requires
a one-time inspection of pre-SB 32-JM7862 Revision 3 MLG
installations and, depending on findings, applicable corrective
action(s).

The MCAI can be found in the AD docket on the Internet at: http://www.regulations.gov/#!documentDetail;D=FAA-2014-1093-0002.

Comments

    We gave the public the opportunity to participate in developing
this AD. We received no comments on the NPRM (79 FR 78726, December 31,
2014) or on the determination of the cost to the public.

Conclusion

    We reviewed the relevant data and determined that air safety and
the public interest require adopting the AD as proposed except for
minor editorial changes. We have determined that these minor changes:
     Are consistent with the intent that was proposed in the
NPRM (79 FR 78726, December 31, 2014) for correcting the unsafe
condition; and
     Do not add any additional burden upon the public than was
already proposed in the NPRM (79 FR 78726, December 31, 2014).

Related Service Information Under 1 CFR Part 51

    We reviewed British Aerospace Jetstream Series 3100 and 3200
Service Bulletin No. 32-JM7862, Revision 3,

dated October 3, 2014; and British Aerospace Jetstream Series 3100 and
3200 Service Bulletin No. 32-A-JA140940, Original Issue, dated October
3, 2014. The service information describes procedures for modifying the
LH and RH MLG at the forward spigot and inspecting for migration of the
special washer, taking corrective action as necessary. This service
information is reasonably available; see ADDRESSES for ways to access
this service information.

Costs of Compliance

    We estimate that this AD will affect 44 products of U.S. registry.
We also estimate that it will take about 2 work-hours per product to
comply with the basic requirements of this AD. The average labor rate
is $85 per work-hour. Required parts will cost about $170 per product.
    Based on these figures, we estimate the cost of this AD to the U.S.
operators to be $14,960, or $340 per product.
    We accept modification of the MLG, if done before the effective
date of this AD, using earlier versions of the service information.
However, the earlier versions of the service information require
additional inspections with possible corrective actions.
    In addition, we estimate that any necessary follow-on actions that
may be required if using an earlier version of the service information
would take about 1 work-hour to inspect for special washer migration
and corrosion damage and require parts costing $100 for replacement of
the special washer and application of witness paint, if necessary, for
a cost of $185 per product. We have no way of determining the number of
products that may need these actions.

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, section 106, describes the
authority of the FAA Administrator. ``Subtitle VII: Aviation
Programs,'' describes in more detail the scope of the Agency's
authority.
    We are issuing this rulemaking under the authority described in
``Subtitle VII, Part A, Subpart III, Section 44701: General
requirements.'' Under that section, Congress charges the FAA with
promoting safe flight of civil aircraft in air commerce by prescribing
regulations for practices, methods, and procedures the Administrator
finds necessary for safety in air commerce. This regulation is within
the scope of that authority because it addresses an unsafe condition
that is likely to exist or develop on products identified in this
rulemaking action.

Regulatory Findings

    We determined that this AD will not have federalism implications
under Executive Order 13132. This AD will not have a substantial direct
effect on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.
    For the reasons discussed above, I certify this AD:
    (1) Is not a ``significant regulatory action'' under Executive
Order 12866,
    (2) Is not a ``significant rule'' under the DOT Regulatory Policies
and Procedures (44 FR 11034, February 26, 1979),
    (3) Will not affect intrastate aviation in Alaska, and
    (4) Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.

Examining the AD Docket

    You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2014-
1093; or in person at the Docket Management Facility between 9 a.m. and
5 p.m., Monday through Friday, except Federal holidays. The AD docket
contains the NPRM, the regulatory evaluation, any comments received,
and other information. The street address for the Docket Office
(telephone<PHONE_NUMBER>) is in the ADDRESSES section. Comments will
be available in the AD docket shortly after receipt.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

Adoption of the Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA amends 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

     Authority: 49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. The FAA amends Sec.  39.13 by removing Amendment 39-17807 (79 FR
17395, March 28, 2014) and adding the following new AD:

2015-06-01 British Aerospace Regional Aircraft: Amendment 39-18119;
Docket No. FAA-2014-1093; Directorate Identifier 2014-CE-035-AD.

(a) Effective Date

    This airworthiness directive (AD) becomes effective April 24,
2015.

(b) Affected ADs

    This AD supersedes AD 2014-06-03, Amendment 39-17806 (79 FR
17395; March 28, 2014).

(c) Applicability

    This AD applies to British Aerospace Regional Aircraft Jetstream
Series 3101 and Jetstream Model 3201 airplanes, all serial numbers,
certificated in any category.

(d) Subject

    Air Transport Association of America (ATA) Code 32: Landing
Gear.

(e) Reason

    This AD was prompted by mandatory continuing airworthiness
information (MCAI) originated by an aviation authority of another
country to identify and correct an unsafe condition on an aviation
product. The MCAI describes the unsafe condition as stress corrosion
cracking of the main landing gear (MLG) spigot housing. We are
issuing this AD to prevent corrosion cracking of the MLG spigot
housing. This condition, if not corrected, could cause structural
failure of the MLG resulting in loss of control of the airplane
during take-off or landing.

(f) Actions and Compliance

    Unless already done, do the following actions in paragraphs
(f)(1) through (f)(11) of this AD, including all subparagraphs, as
applicable.
    (1) At the next scheduled MLG removal, modify the installation
of the left hand (LH) and right hand (RH) MLG at the forward spigot
following British Aerospace Jetstream Series 3100 and 3200 Service
Bulletin No. 32-JM7862, Revision 3, dated October 3, 2014.

    Note to paragraph (f)(1) of this AD: The next scheduled MLG
removal may be for non-destructive testing or overhaul, as
applicable.

    (2) If done before April 24, 2015 (the effective date of this
AD), we will accept modification of the LH or RG MLG following
British Aerospace Jetstream Series 3100 & 3200 Service Bulletin SB
32-JM7862, Revision 2, dated June 13, 2014; or British Aerospace
Jetstream Series 3100 & 3200 Service Bulletin 32-JM7862, Revision 1,
dated May 7, 2013, for compliance with paragraph (f)(1) of this AD.
    (3) For airplanes that, before April 24, 2015 (the effective
date of this AD), have been modified following British Aerospace
Jetstream Series 3100 & 3200 Service Bulletin 32-JM7862, Revision 2,
dated June 13, 2014, visually inspect the LH and RH MLG to detect
migration of a special washer following the instructions in Part 1
of British Aerospace Jetstream Series 3100 & 3200 Service Bulletin
32-A-JA140940, Original Issue, dated October 3, 2014, at the

compliance time listed in paragraph (f)(3)(i) or (f)(3)(ii) of this
AD, as applicable.
    (i) For MLG configuration equipped with DTD5094 cylinder: Within
the next 200 flight cycles after April 24, 2015 (the effective date
of this AD) or within the next 2 months after the effective date of
this AD, whichever occurs first.
    (ii) For MLG configuration equipped with L161 cylinder: Within
the next 600 flight cycles after April 24, 2015 (the effective date
of this AD) or within the next 6 months after April 24, 2015 (the
effective date of this AD), whichever occurs first.
    (4) If evidence of migration of the special washer was detected
during the inspection required in paragraph (f)(3) of this AD,
within the applicable compliance time specified in paragraph
(f)(3)(i) or (f)(3)(ii) of this AD, do the corrective actions on the
LH or RH MLG, as applicable, following Part 2 of British Aerospace
Jetstream Series 3100 & 3200 Service Bulletin 32-A-JA140940,
Original Issue, dated October 3, 2014.
    (5) If no evidence of migration of the special washer was
detected during the inspection required in paragraph (f)(3) of this
AD, before further flight, apply a witness paint over the special
washer tab and onto the MLG spigot housing (LH and RH MLG) following
Part 1 of British Aerospace Jetstream Series 3100 & 3200 Service
Bulletin 32-A-JA140940, Original Issue, dated October 3, 2014.
    (6) For airplanes that, before April 24, 2015 (the effective
date of this AD), have been modified following British Aerospace
Jetstream Series 3100 & 3200 Service Bulletin 32-JM7862, Revision 1,
dated May 7, 2013, do all of the actions on the MLG cylinder (LH
and/or RH, as applicable) following the instructions in Part 2 of
British Aerospace Jetstream Series 3100 & 3200 Service Bulletin 32-
A-JA140940, Original Issue, dated October 3, 2014, at the compliance
time listed in paragraph (f)(6)(i) or (f)(6)(ii), as applicable.
    (i) For MLG configuration equipped with DTD5094 cylinder: Within
the next 200 flight cycles after April 24, 2015 (the effective date
of this AD) or within the next 2 months after April 24, 2015 (the
effective date of this AD), whichever occurs first.
    (ii) For MLG configuration equipped with L161 cylinder: Within
the next 600 flight cycles after April 24, 2015 (the effective date
of this AD) or within the next 6 months after April 24, 2015 (the
effective date of this AD), whichever occurs first.
    (7) If any wear, corrosion, or damage is detected during the
inspection required in either paragraph (f)(3) or (f)(6), as
applicable, of this AD, before further flight, do all of the
corrective actions (including application of the a witness paint)
following the instructions in Part 2 of British Aerospace Jetstream
Series 3100 & 3200 Service Bulletin 32-A-JA140940, Original Issue,
dated October 3, 2014.
    (8) Between 30 and 45 days after doing the action required in
either paragraph (f)(3) or (f)(6) of this AD or between the next 20
to 30 flight cycles after doing the action required in either
paragraph (f)(3) or (f)(6) of this AD, whichever occurs first,
inspect the witness paint applied as required in either paragraph
(f)(5) or (f)(7) of this AD following the instructions in Part 3 of
British Aerospace Jetstream Series 3100 & 3200 Service Bulletin 32-
A-JA140940, Original Issue, dated October 3, 2014.
    (9) If any damaged paint is detected during the inspection
required in paragraph (f)(8) of this AD, before further flight,
contact British Aerospace Regional Aircraft to obtain FAA-approved
repair instructions approved specifically for this AD and
incorporate those instructions. You may find the contact information
for British Aerospace Regional Aircraft in paragraph (h) of this AD.
    (10) As of April 24, 2015 (the effective date of this AD), do
not install a LH or RH MLG on any of the applicable airplanes unless
it has passed all of the inspections required by this AD.
    (11) For all airplanes: The compliance times for paragraphs
(f)(3)(i), (f)(3)(ii), (f)(6)(i), (f)(6)(ii), and (f)(8) of this AD
are presented in flight cycles (landings). If the total flight
cycles have not been kept, multiply the total number of airplane
hours time-in-service (TIS) by 0.75 to calculate the cycles. You may
use the following as an example for this AD:
    (i) 200 hours TIS x .75 = 150 cycles; or
    (ii) 600 hours TIS x .75 = 450 cycles.

(g) Other FAA AD Provisions

    The following provisions also apply to this AD:
    (1) Alternative Methods of Compliance (AMOCs): The Manager,
Standards Office, FAA, has the authority to approve AMOCs for this
AD, if requested using the procedures found in 14 CFR 39.19. Send
information to ATTN: Taylor Martin, Aerospace Engineer, FAA, Small
Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri
64106; telephone:<PHONE_NUMBER>; fax:<PHONE_NUMBER>; email:
<EMAIL_ADDRESS>Before using any approved AMOC on any
airplane to which the AMOC applies, notify your appropriate
principal inspector (PI) in the FAA Flight Standards District Office
(FSDO), or lacking a PI, your local FSDO.
    (2) Airworthy Product: For any requirement in this AD to obtain
corrective actions from a manufacturer or other source, use these
actions if they are FAA-approved. Corrective actions are considered
FAA-approved if they are approved by the State of Design Authority
(or their delegated agent). You are required to assure the product
is airworthy before it is returned to service.

(h) Related Information

    Refer to MCAI found in the European Aviation Safety Agency
(EASA), which is the Technical Agent for the Member States of the
European Community, AD No. 2014-0239, dated November 3, 2014; and
British Aerospace Jetstream Series 3100 & 3200 Service Bulletin SB
32-JA851226, Revision 5, dated April 30, 2013; British Aerospace
Jetstream and British Aerospace Jetstream Series 3100 & 3200 Service
Bulletin 32-JM7862, Revision 1, dated May 7, 2013, for related
information. The MCAI can be found in the AD docket on the Internet
at http://www.regulations.gov/#!documentDetail;D=FAA-2014-1093-0002.

(i) Material Incorporated by Reference

    (1) The Director of the Federal Register approved the
incorporation by reference (IBR) of the service information listed
in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
    (2) You must use this service information as applicable to do
the actions required by this AD, unless the AD specifies otherwise.
    (i) British Aerospace Jetstream Series 3100 and 3200 Service
Bulletin No. 32-JM7862, Revision 3, dated October 3, 2014.
    (ii) British Aerospace Jetstream Series 3100 & 3200 Service
Bulletin 32-A-JA140940, Original Issue, dated October 3, 2014.
    (3) For service information identified in this AD, contact BAE
Systems (Operations) Ltd, Customer Information Department, Prestwick
International Airport, Ayrshire, KA9 2RW, Scotland, United Kingdom;
phone: +44 1292 675207, fax: +44 1292 675704; email:
<EMAIL_ADDRESS>Internet: http://www.jetstreamcentral.com.
    (4) You may view this service information the FAA, Small
Airplane Directorate, 901 Locust, Kansas City, Missouri 64106. For
information on the availability of this material at the FAA, call
(816) 329-4148. In addition, you can access this service information
on the Internet at http://www.regulations.gov by searching for and
locating Docket No. FAA-2014-1093.
    (5) You may view this service information that is incorporated
by reference at the National Archives and Records Administration
(NARA). For information on the availability of this material at
NARA, call<PHONE_NUMBER>, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.

    Issued in Kansas City, Missouri, on March 10, 2015.
Pat Mullen,
Acting Manager, Small Airplane Directorate, Aircraft Certification
Service.
[FR Doc. 2015-06053 Filed 3-19-15; 8:45 am]
 BILLING CODE 4910-13-P


[Federal Register Volume 83, Number 29 (Monday, February 12, 2018)]
[Notices]
[Pages 6038-6039]
[FR Doc No: 2018-02756]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2015-E-3877]

Determination of Regulatory Review Period for Purposes of Patent
Extension; AKYNZEO

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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

SUMMARY: The Food and Drug Administration (FDA or the Agency) has
determined the regulatory review period for AKYNZEO and is publishing
this notice of that determination as required by law. FDA has made the
determination because of the submission of an application to the
Director of the U.S. Patent and Trademark Office (USPTO), Department of
Commerce, for the extension of a patent which claims that human drug
product.

DATES: Anyone with knowledge that any of the dates as published (see
the SUPPLEMENTARY INFORMATION section) are incorrect may submit either
electronic or written comments and ask for a redetermination by April
13, 2018. Furthermore, any interested person may petition FDA for a
determination regarding whether the applicant for extension acted with
due diligence during the regulatory review period by August 13, 2018.
See ``Petitions'' in the SUPPLEMENTARY INFORMATION section for more
information.

ADDRESSES: You may submit comments as follows. Please note that late,
untimely filed comments will not be considered. Electronic comments
must be submitted on or before April 13, 2018. The https://www.regulations.gov electronic filing system will accept comments until
midnight Eastern Time at the end of April 13, 2018. Comments received
by mail/hand delivery/courier (for written/paper submissions) will be
considered timely if they are postmarked or the delivery service
acceptance receipt is on or before that date.

Electronic Submissions

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

Written/Paper Submissions

    Submit written/paper submissions as follows:
     Mail/Hand delivery/Courier (for written/paper
submissions): Dockets Management Staff (HFA-305), Food and Drug
Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
     For written/paper comments submitted to the Dockets
Management Staff, FDA will post your comment, as well as any
attachments, except for information submitted, marked and identified,
as confidential, if submitted as detailed in ``Instructions.''
    Instructions: All submissions received must include the Docket No.
FDA-2015-E-3877 for ``Determination of Regulatory Review Period for
Purposes of Patent Extension; AKYNZEO.'' Received comments, those filed
in a timely manner (see ADDRESSES), will be placed in the docket and,
except for those submitted as ``Confidential Submissions,'' publicly
viewable at https://www.regulations.gov or at the Dockets Management
Staff between 9 a.m. and 4 p.m., Monday through Friday.
     Confidential Submissions--To submit a comment with
confidential information that you do not wish to be made publicly
available, submit your comments only as a written/paper submission. You
should submit two copies total. One copy will include the information
you claim to be confidential with a heading or cover note that states
``THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.'' The Agency will
review this copy, including the claimed confidential information, in
its consideration of comments. The second copy, which will have the
claimed confidential information redacted/blacked out, will be
available for public viewing and posted on https://www.regulations.gov.
Submit both copies to the Dockets Management Staff. If you do not wish
your name and contact information to be made publicly available, you
can provide this information on the cover sheet and not in the body of
your comments and you must identify this information as
``confidential.'' Any information marked as ``confidential'' will not
be disclosed except in accordance with Sec.  10.20 (21 CFR 10.20) and
other applicable disclosure law. For more information about FDA's
posting of comments to public dockets, see 80 FR 56469, September 18,
2015, or access the information at: http://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-23389.pdf.
    Docket: For access to the docket to read background documents or
the electronic and written/paper comments received, go to https://www.regulations.gov and insert the docket number, found in brackets in
the heading of this document, into the ``Search'' box and follow the
prompts and/or go to the Dockets Management Staff, 5630 Fishers Lane,
Rm. 1061, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT: Beverly Friedman, Office of Regulatory
Policy, Food and Drug Administration, 10903 New Hampshire Ave., Bldg.
51, Rm. 6250, Silver Spring, MD 20993,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

I. Background

    The Drug Price Competition and Patent Term Restoration Act of 1984
(Pub. L. 98-417) and the Generic Animal Drug and Patent Term
Restoration Act (Pub. L. 100-670) generally provide that a patent may
be extended for a period of up to 5 years so long as the patented item
(human drug product, animal drug product, medical device, food
additive, or color additive) was subject to regulatory review by FDA
before the item was marketed. Under these acts, a product's regulatory
review period forms the basis for determining the amount of extension
an applicant may receive.
    A regulatory review period consists of two periods of time: A
testing phase and an approval phase. For human drug products, the
testing phase begins when the exemption to permit the clinical
investigations of the drug becomes effective and runs until the
approval phase begins. The approval phase starts

with the initial submission of an application to market the human drug
product and continues until FDA grants permission to market the drug
product. Although only a portion of a regulatory review period may
count toward the actual amount of extension that the Director of USPTO
may award (for example, half the testing phase must be subtracted as
well as any time that may have occurred before the patent was issued),
FDA's determination of the length of a regulatory review period for a
human drug product will include all of the testing phase and approval
phase as specified in 35 U.S.C. 156(g)(1)(B).
    FDA has approved for marketing the human drug product AKYNZEO
(netupitant/palonosetron hydrochloride). AKYNZEO is indicated for the
prevention of acute and delayed nausea and vomiting associated with
initial and repeat courses of cancer chemotherapy including, but not
limited to, highly emetogenic chemotherapy. Subsequent to this
approval, the USPTO received a patent term restoration application for
AKYNZEO (U.S. Patent No. 6,297,375) from Hoffmann-La Roche Inc., and
the USPTO requested FDA's assistance in determining this patent's
eligibility for patent term restoration. In a letter dated October 30,
2015, FDA advised the USPTO that this human drug product had undergone
a regulatory review period and that the approval of AKYNZEO represented
the first permitted commercial marketing or use of the product.
Thereafter, the USPTO requested that FDA determine the product's
regulatory review period.

II. Determination of Regulatory Review Period

    FDA has determined that the applicable regulatory review period for
AKYNZEO is 1,858 days. Of this time, 1,479 days occurred during the
testing phase of the regulatory review period, while 379 days occurred
during the approval phase. These periods of time were derived from the
following dates:
    1. The date an exemption under section 505(i) of the Federal Food,
Drug, and Cosmetic Act (FD&C Act) (21 U.S.C. 355(i)) became effective:
September 10, 2009. FDA has verified the applicant's claim that
September 10, 2009, is the date the investigational new drug
application (IND) became effective.
    2. The date the application was initially submitted with respect to
the human drug product under section 505(b) of the FD&C Act: September
27, 2013. The applicant claims September 25, 2013, as the date the new
drug application (NDA) for AKYNZEO (NDA 205718) was initially
submitted. However, FDA records indicate that NDA 205718 was submitted
on September 27, 2013.
    3. The date the application was approved: October 10, 2014. FDA has
verified the applicant's claim that NDA 205718 was approved on October
10, 2014.
    This determination of the regulatory review period establishes the
maximum potential length of a patent extension. However, the USPTO
applies several statutory limitations in its calculations of the actual
period for patent extension. In its application for patent extension,
this applicant seeks 1,118 days of patent term extension.

III. Petitions

    Anyone with knowledge that any of the dates as published are
incorrect may submit either electronic or written comments and, under
21 CFR 60.24, ask for a redetermination (see DATES). Furthermore, as
specified in Sec.  60.30 (21 CFR 60.30), any interested person may
petition FDA for a determination regarding whether the applicant for
extension acted with due diligence during the regulatory review period.
To meet its burden, the petition must comply with all the requirements
of Sec.  60.30, including but not limited to: Must be timely (see
DATES), must be filed in accordance with Sec.  10.20, must contain
sufficient facts to merit an FDA investigation, and must certify that a
true and complete copy of the petition has been served upon the patent
applicant. (See H. Rept. 857, part 1, 98th Cong., 2d sess., pp. 41-42,
1984.) Petitions should be in the format specified in 21 CFR 10.30.
    Submit petitions electronically to https://www.regulations.gov at
Docket No. FDA-2013-S-0610. Submit written petitions (two copies are
required) to the Dockets Management Staff (HFA-305), Food and Drug
Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.

    Dated: February 7, 2018.
Leslie Kux,
Associate Commissioner for Policy.
[FR Doc. 2018-02756 Filed 2-9-18; 8:45 am]
 BILLING CODE 4164-01-P


[Federal Register: April 13, 2009 (Volume 74, Number 69)]
[Notices]
[Page 16901-16903]
[DOCID:fr13ap09-127]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-59708; File No. SR-NYSEArca-2009-12]

Self-Regulatory Organizations; NYSE Arca, Inc.; Order Approving
Proposed Rule Change Relating to SPDR Barclays Capital Convertible Bond
ETF

April 6, 2009.

I. Introduction

    On February 18, 2009, NYSE Arca, Inc. (``Exchange'' or ``NYSE
Arca''), through its wholly owned subsidiary, NYSE Arca Equities, Inc.
(``NYSE Arca Equities''), filed with the Securities and Exchange
Commission (``Commission'') pursuant to Section 19(b)(1) of the
Securities Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4
thereunder,\2\ a proposed rule change to list and trade shares
(``Shares'') of the SPDR[supreg] Barclays Capital Convertible Bond ETF.
The proposed rule change was published for comment in the Federal
Register on March 6, 2009.\3\ The Commission received no comment
letters on the proposed rule change. This order approves the proposed
rule change.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ See Securities Exchange Act Release No. 59459 (February 26,
2009), 74 FR 9860 (``Notice'').
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II. Description of the Proposed Rule Change

    The Exchange proposes to list and trade the SPDR[supreg] Barclays
Capital Convertible Bond ETF (``Fund'') \4\ under NYSE Arca Equities
Rule 5.2(j)(3), the Exchange's listing standards for Investment Company
Units (``Units'').\5\
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    \4\ See the Registration Statement on Form N-1A of the SPDR
Series Trust, dated January 15, 2009 (File Nos. 333-57793 and 811-
08839) (``Registration Statement'').
    \5\ An Investment Company Unit is a security that represents an
interest in a registered investment company that holds securities
comprising, or otherwise based on or representing an interest in, an
index or portfolio of securities (or holds securities in another
registered investment company that holds securities comprising, or
otherwise based on or representing an interest in, an index or
portfolio of securities). See NYSE Arca Equities Rule 5.2(j)(3)(A).

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    The Fund's investment objective is to provide investment results
that, before fees and expenses, correspond generally to the price and
yield performance of the Barclays Capital U.S. Convertible Bond $500MM
Index (``Index''), which aims to track the performance of the U.S.
dollar-denominated convertibles markets with outstanding issue sizes
greater than $500 million. The Index includes the following major
classes of convertible securities--cash pay bonds, zero-coupon/Original
Issue Discount bonds, preferred securities, and mandatories.
    The Index includes both U.S. convertible bonds and convertible
preferred equity securities.\6\ The Index components consisting of U.S.
convertible bonds separately meet the criteria set forth in Commentary
.02(a) of Rule 5.2(j)(3) applicable to Units based on a fixed income
index or portfolio. However, the Index components consisting of
convertible preferred stocks do not separately meet the criteria set
forth in Commentary .01(a) of Rule 5.2(j)(3) applicable to Units based
on U.S. indexes or portfolios.
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    \6\ Commentary .03 to Rule 5.2(j)(3) provides that the
Corporation may list a series of Units based on a combination of
indexes or a portfolio of component securities representing the U.S.
or domestic equity market, the international equity market, and the
fixed income market for listing and trading pursuant to Rule 19b-
4(e) under the Act provided each index or portfolio of equity and
fixed income component securities separately meet either the
criteria set forth in Commentary .01(a) of Rule 5.2(j)(3)
(applicable to Units based on U.S., international or global equity
indexes or portfolios) or Commentary .02(a) (applicable to Units
based on a fixed income index or portfolio).
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    The Exchange represents that: (i) except for Commentaries
.01(a)(A)(2) \7\ and .01(a)(A)(5) \8\ to NYSE Arca Equities Rule
5.2(j)(3), the Shares currently satisfy all other of the generic
listing standards under the rule; (ii) the continued listing standards
under NYSE Arca Equities Rules 5.2(j)(3) and 5.5(g)(2) applicable to
Units shall apply to the Shares; and (iii) the Trust is required to
comply with Rule 10A-3 \9\ under the Act for the initial and continued
listing of the Shares. Additionally, the Exchange represents that the
Shares will comply with all other requirements applicable to Units
including, but not limited to, requirements relating to the
dissemination of key information such as the Index value and Intraday
Indicative Value, rules governing the trading of equity securities,
trading hours, trading halts, surveillance, firewalls and Information
Bulletins to ETP Holders, as set forth in prior Commission orders
approving the generic listing rules applicable to the listing and
trading of Units.\10\ Detailed descriptions of the Fund, the Underlying
Index, procedures for creating and redeeming Shares, transaction fees
and expenses, dividends, distributions, taxes, and reports to be
distributed to beneficial owners of the Shares can be found in the
Registration Statement or on the Web site for the Fund (http://
www.SPDRETFs.com).\11\
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    \7\ Commentary .01(a)(A)(2) to NYSE Arca Equities Rule 5.2(j)(3)
provides that component stocks that in the aggregate account for at
least 90% of the weight of the index or portfolio each shall have a
minimum worldwide monthly trading volume during each of the last six
months of at least 250,000 shares. According to the Exchange, the
Index does not meet the requirements of Commentary .01(a)(A)(2) in
that convertible preferred stocks accounting for 78.56% of the
weight of the convertible preferred portion of the Index each had a
minimum worldwide monthly trading volume during each of the last six
months of at least 250,000 shares, as of November 30, 2008.
    \8\ Commentary .01(a)(A)(5) to NYSE Arca Equities Rule 5.2(j)(3)
provides that all securities in the Index or portfolio shall be US
Component Stocks, as defined in Rule 5.2(j)(3) listed on a national
securities exchange and shall be NMS Stocks as defined in Rule 600
of Regulation NMS under the Act. The Exchange states that, while the
Index does not include any non-U.S. securities, as of November 30,
2008, six of the 31 convertible preferred securities in the Index,
accounting for 8% of the Index weight, were not listed on a national
securities exchange; those issues were traded over-the-counter.
    \9\ 17 CFR 240.10A-3.
    \10\ See, e.g., Securities Exchange Act Release Nos. 55783 (May
17, 2007), 72 FR 29194 (May 24, 2007) (SR-NYSEArca-2007-36) (order
approving generic listing standards for Units based on fixed income
indexes); 44551 (July 12, 2001), 66 FR 37716 (July 19, 2001) (SR-
PCX-2001-14) (order approving generic listing standards for Units
and Portfolio Depositary Receipts); and 41983 (October 6, 1999), 64
FR 56008 (October 15, 1999) (SR-PCX-98-29) (order approving rules
for listing and trading of Units).
    \11\ See also Notice, supra, note 3.
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III. Discussion and Commission's Findings

    After careful review, the Commission finds that NYSE Arca's
proposal to list and trade the Shares is consistent with the Act and
the rules and regulations thereunder applicable to a national
securities exchange.\12\ In particular, the Commission finds that the
proposed rule change is consistent with Section 6(b)(5) of the Act,\13\
in that it is designed to prevent fraudulent and manipulative acts and
practices, to promote just and equitable principles of trade, to foster
cooperation and coordination with persons engaged in facilitating
transactions in securities, to remove impediments to and perfect the
mechanism of a free and open market and a national market system, and,
in general, to protect investors and the public interest.
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    \12\ In approving this proposed rule change, the Commission has
considered the proposed rule's impact on efficiency, competition,
and capital formation. See 15 U.S.C. 78c(f).
    \13\ 15 U.S.C. 78f(b)(5).
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    NYSE Arca Equities Rule 5.2(j)(3) permits the Exchange to consider
qualifying Units for listing and trading pursuant to Rule 19b-4(e)
under the Act. The Shares, however, do not qualify for generic listing
under the Exchange's rule because, although the Index components
consisting of U.S. convertible bonds separately meet the criteria set
forth in Commentary .02(a) of Rule 5.2(j)(3) applicable to Units based
on a fixed income index or portfolio, the Index components consisting
of convertible preferred stocks do not separately meet the criteria set
forth in Commentaries .01(a)(A)(2) and .01(a)(A)(5) of the rule
applicable to Units based on U.S. indexes or portfolios.\14\
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    \14\ See notes 7 and 8, supra.
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    The Commission believes that the listing and trading of the Shares
is consistent with the Act. The Shares currently satisfy all but two of
the generic listing standards under the rule, and the Commission
believes that the composition of the Index, despite failing to satisfy
the requirements of Commentaries .01(a)(A)(2) and .01(a)(A)(5) to NYSE
Arca Equities Rule 5.2(j)(3), does not raise any regulatory concerns.
Additionally, the continued listing standards under NYSE Arca Equities
Rules 5.2(j)(3) and 5.5(g)(2) applicable to Units will apply to the
Shares, and the Trust is required to comply with Rule 10A-3 \15\ under
the Act for the initial and continued listing of the Shares. Finally,
the Commission notes that it has not received any comments regarding
the proposed rule change.
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    \15\ 17 CFR 240.10A-3.
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IV. Conclusion

    For the foregoing reasons, the Commission believes that the
Exchange's proposal to list and trade the Shares is consistent with the
Act. This order is based on the Exchange's representations.
    It is therefore ordered, pursuant to Section 19(b)(2) of the
Act,\16\ that the proposed rule change (SR-NYSEArca-2009-12) be, and it
hereby is, approved.
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    \16\ 15 U.S.C. 78s(b)(1).

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    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\17\
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    \17\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
[FR Doc. E9-8326 Filed 4-10-09; 8:45 am]

BILLING CODE 8010-01-P