Animal and Plant Health Inspection Service
Forest Service
Antitrust Division
Foreign-Trade Zones Board
International Trade Administration
National Oceanic and Atmospheric Administration
Federal Energy Regulatory Commission
Agency for Healthcare Research and Quality
Children and Families Administration
Food and Drug Administration
Health Resources and Services Administration
National Institutes of Health
Agency for Healthcare Research and Quality
Coast Guard
Federal Emergency Management Agency
U.S. Customs and Border Protection
Fish and Wildlife Service
Geological Survey
Indian Affairs Bureau
Land Management Bureau
Antitrust Division
Parole Commission
Mine Safety and Health Administration
Institute of Museum and Library Services
Federal Aviation Administration
National Highway Traffic Safety Administration
Saint Lawrence Seaway Development Corporation
Surface Transportation Board
Foreign Assets Control Office
Internal Revenue Service
Consult the Reader Aids section at the end of this page for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.gpo.gov and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Final rule.
We are adopting a new airworthiness directive (AD) for certain Airbus Model A330–200, A330–300, A340–200 and A340–300 series airplanes. This AD was prompted by a report that revealed the wheel axles of the main landing gear (MLG) were machined with a radius as small as 0.4 millimeters. This AD requires replacing the wheel axle of the MLG with a serviceable part. We are issuing this AD to prevent fatigue of the wheel axle of the MLG, which could adversely affect the structural integrity of the airplane.
This AD becomes effective May 23, 2013.
The Director of the Federal Register approved the incorporation by reference of certain publications listed in this AD as of May 23, 2013.
You may examine the AD docket on the Internet at
Vladimir Ulyanov, Aerospace Engineer, International Branch, ANM–116, Transport Airplane Directorate, FAA, 1601 Lind Avenue SW., Renton, Washington 98057–3356; telephone (425) 227–1138; fax (425) 227–1149.
We issued a Notice of Proposed Rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
EASA [European Aviation Safety Agency] has received a report via Airbus and Messier-Bugatti-Dowty Ltd, from a Maintenance repair organisation, concerning a specific repair, accomplished on certain MLG wheel axles. Investigations revealed that the axles have been machined with a radius as small as 0.4 mm.
This condition, if not corrected, has a detrimental effect on the fatigue lives of these parts, possibly affecting the structural integrity of the aeroplane. Fatigue analyses were performed, the results of which indicated that the life limit of the affected MLG wheel axles must be reduced to below the one stated in the A330 and A340 Airbus Airworthiness Limitation Section (ALS) Part 1.
For the reasons described above, this [EASA) AD [2011–0170, dated September 7, 2011] requires the replacement of the MLG wheel axles before reaching the new reduced demonstrated life limit.
You may obtain further information by examining the MCAI in the AD docket.
We gave the public the opportunity to participate in developing this AD. We received no comments on the NPRM (77 FR 51729, August 27, 2012), or on the determination of the cost to the public.
Since the NPRM (77 FR 51729, August 27, 2012) was issued, we have reviewed Airbus Alert Operators Transmission (AOT) A330–32A–3256, Revision 01, including Appendix 1, dated October 18, 2012 (for Model A330–200 and –300 series airplanes); and Airbus AOT A340–32A–4292, Revision 01, including Appendix 1, dated October 18, 2012 (for Model A340–200 and –300 series airplanes). This service information includes additional wheel axle serial numbers and corrects an incorrectly listed serial number. We have revised paragraphs (g), (h), and (k) (paragraph (j) of the NPRM) of this AD to refer to the new service information. We have coordinated this change with EASA.
We have also added new paragraph (j), “Credit for Previous Actions,” to this AD to provide credit for actions performed before the effective date of this AD using Airbus All Operator Telex A330–32A3256, including Appendix 1, dated August 24, 2011; and Airbus All Operator Telex A340–32A4292, including Appendix 1, dated August 24, 2011.
We reviewed the available data, and determined that air safety and the public interest require adopting the AD with the changes described previously—and minor editorial changes. We have determined that these changes:
• Are consistent with the intent that was proposed in the NPRM (77 FR 51729, August 27, 2012) for correcting the unsafe condition; and
• Do not add any additional burden upon the public than was already proposed in the NPRM (77 FR 51729, August 27, 2012).
We estimate that this AD will affect 59 products of U.S. registry. We also estimate that it will take about 48 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 $153,443 per product. Where the service information lists required parts costs that are covered under warranty, we have assumed that there will be no charge for these parts. As we do not control warranty coverage for affected parties, some parties may incur costs higher than estimated here. Based on these figures, we estimate the cost of this AD to the U.S. operators to be $9,293,857, or $157,523 per product.
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
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.
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 that 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.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
You may examine the AD docket on the Internet at
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This airworthiness directive (AD) becomes effective May 23, 2013.
None.
This AD applies to Airbus Model A330–201, –202, –203, –223, –243, –301, –302, –303, –321, –322, –323, –341, –342, and –343 airplanes; and Model A340–211, –212, –213, –311, –312, and –313 airplanes; certificated in any category; all manufacturer serial numbers, except those on which Airbus modification 54500 has been embodied in production.
Air Transport Association (ATA) of America Code 32: Landing Gear.
This AD was prompted by a report that revealed the wheel axles were machined with a radius as small as 0.4 millimeters. We are issuing this AD to prevent fatigue of the wheel axle of the main landing gear (MLG), which could adversely affect the structural integrity of the airplane.
You are responsible for having the actions required by this AD performed within the compliance times specified, unless the actions have already been done.
(1) For the purpose of this AD, an affected MLG wheel axle is defined as a MLG axle having a part number and serial number specified in Part 1 of Appendix 1 of Airbus Alert Operators Transmission (AOT) A330–32A–3256, Revision 01, dated October 18, 2012 (for Model A330–200 and –300 series airplanes); or Airbus AOT A340–32A–4292, Revision 01, dated October 18, 2012 (for Model A340–200 and –300 series airplanes).
(2) After removal from an airplane, an affected MLG wheel axle that has reached its life limit is considered an unserviceable part.
(3) The term “life limit” used in this AD means a post-repair life limit.
At the later of the times specified in paragraph (h)(1) or (h)(2) of this AD: Replace all affected MLG wheel axles with serviceable parts, in accordance with the instructions of Airbus AOT A330–32A–3256, Revision 01, including Appendix 1, dated October 18, 2012 (for Model A330–200 and –300 series airplanes); or Airbus AOT A340–32A–4292, Revision 01, including Appendix 1, dated October 18, 2012 (for Model A340–200 and –300 series airplanes).
(1) Before the accumulation of the applicable landings or flight hours specified in table 1 to paragraph (h)(1) of this AD. The “Post-repair MLG Wheel Axle Life Limit” must be counted from the date of installation of the MLG wheel axle on an airplane which occurs after the date of repair specified in Part 1 of Appendix 1 of Airbus AOT A330–32A–3256, Revision 01, dated October 18, 2012 (for Model A330–200 and –300 series airplanes); or Airbus AOT A340–32A–4292, Revision 01, dated October 18, 2012 (for Model A340–200 and –300 series airplanes).
(2) Within 24 months after the effective date of this AD without exceeding the applicable landings or flight hours specified in table 2 to paragraph (h)(2) of this AD. The “Post-repair MLG Wheel Axle Flight Hours or Landings, . . . not to be Exceeded” must
As of the effective date of this AD: An affected MLG wheel axle may be installed on an airplane, provided the MLG wheel axle has not exceeded the limits specified in table 1 to paragraph (h)(1) of this AD and it is replaced with a serviceable part before reaching the life limit defined in table 1 to paragraph (h)(1) of this AD.
This paragraph provides credit for the actions required by paragraph (h) of this AD with respect to the affected MLG wheel axle defined in paragraph (g)(1) of this AD, if those actions were performed before the effective date of this AD using the applicable service information specified in paragraph (j)(1) or (j)(2) of this AD, which is not incorporated by reference in this AD.
(1) Airbus All Operator Telex A330–32A3256, including Appendix 1, dated August 24, 2011 (for Model A330–200 and –300 series airplanes).
(2) Airbus All Operator Telex A340–32A4292, including Appendix 1, dated August 24, 2011 (for Model A340–200 and –300 series airplanes).
The following provisions also apply to this AD:
(1)
(2)
(1) Refer to MCAI European Aviation Safety Agency Airworthiness Directive 2011–0170, dated September 7, 2011, and the service information specified in paragraphs (l)(1)(i) and (l)(1)(ii) of this AD, for related information.
(i) Airbus AOT A330–32A–3256, Revision 01, including Appendix 1, dated October 18, 2012.
(ii) Airbus AOT A340–32A–4292, Revision 01, including Appendix 1, dated October 18, 2012.
(2) For service information identified in this AD, contact Airbus SAS—Airworthiness Office—EAL, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 45 80; email
(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) Airbus Alert Operators Transmission (AOT) A330–32A–3256, Revision 01, including Appendix 1, dated October 18, 2012. The Document number and revision level are not identified on pages 2–5 of this AOT; the revision date is identified on only page 1 of this AOT and the first page of Appendix 1 of this AOT.
(ii) AOT A340–32A–4292, Revision 01, including Appendix 1, dated October 18, 2012. The Document number and revision level are not identified on pages 2–5 of this AOT; the revision date is identified on only page 1 of this AOT and the first page of Appendix 1 of this AOT.
(3) For service information identified in this AD, contact Airbus SAS—Airworthiness Office—EAL, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 45 80; email
(4) You may review copies of the service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425–227–1221.
(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 202–741–6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for Eurocopter France (ECF) Model AS332C, L, and L1 helicopters to require an initial and repetitive inspections of the outer skin, butt strap, and fuselage frame for a crack and modification of the helicopter. This AD was prompted by an AD issued by the
This AD is effective May 23, 2013.
The Director of the Federal Register approved the incorporation by reference of a certain document listed in this AD as of May 23, 2013.
For service information identified in this AD, contact American Eurocopter Corporation, 2701 N. Forum Drive, Grand Prairie, Texas 75052; telephone (972) 641–0000 or (800) 232–0323; fax (972) 641–3775; or at
You may examine the AD docket on the Internet at
Gary Roach, Aviation Safety Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
On October 16, 2012, at 77 FR 63262, the
EASA issued EASA AD No. 2008–0035–E, dated February 21, 2008, to correct an unsafe condition for the ECF Model AS 332 C, C1, L, and L1 helicopters. EASA advises that a crack was discovered on an ECF Model AS332L helicopter in fuselage frame 5295, which has plates and angles assembled by riveting that corresponds to the first generation frame (before MOD 0722907). The crack in the frame was found because of a crack in the outer skin and in the butt strap where the rail of the main gear box (MGB) sliding cowling is attached to the frame.
We gave the public the opportunity to participate in developing this AD, but we did not receive any comments on the NPRM (77 FR 63262, October 16, 2012).
These helicopters have been approved by the aviation authority of France and are approved for operation in the United States. Pursuant to our bilateral agreement with France, EASA, its technical representative, has notified us of the unsafe condition described in the EASA AD. We are issuing this AD because we evaluated all information provided by EASA and determined the unsafe condition exists and is likely to exist or develop on other helicopters of these same type designs and that air safety and the public interest require adopting the AD requirements as proposed, except we have updated the contact information for American Eurocopter Corporation. This minor editorial change is consistent with the intent of the proposals in the NPRM (77 FR 63262, October 16, 2012) and will not increase the economic burden on any operator nor increase the scope of the AD.
This AD requires you to repair Frame 5295 before further flight rather than contacting the manufacturer. This AD refers to a check as an inspection to be performed by a mechanic versus a check that a pilot can do if specifically allowed by the AD. This AD also does not list the Model AS332C1 in the applicability because this model is not type certificated in the U.S. This AD also does not allow further flight with the outer skin or butt strap cracked unless it is a ferry flight to a repair facility.
Eurocopter has issued Alert Service Bulletin No. 05.00.76, Revision 0, dated February 20, 2008 (ASB), which specifies checking for a crack on the outside of the helicopter, on the skin, and the butt strap near the sliding cowling rail attachment. If a crack is found in the outer skin or butt strap, the ASB specifies visually checking for a crack in Frame 5295. The ASB specifies doing MOD 0726478R2, which consists of cutting out a section of the sliding cowling rails. This cut-out exposes the splice near the rail attachment holes, making it easier to detect a crack in the frame during the 10-hour repetitive inspection and thus reducing the risks of a crack going undetected in Frame 5295. Also, the ASB specifies contacting the manufacturer for the “appropriate repair sheet according to how the crack is situated” if there is a crack in Area 1 of Frame 5295. EASA classified this ASB as mandatory and issued AD No. 2008–0035–E, dated February 21, 2008, to ensure the continued airworthiness of these helicopters.
We estimate that this AD will affect 5 helicopters of U.S. Registry. We estimate that operators may incur the following costs in order to comply with this AD. We estimate that it will take about 4.25 work-hours per helicopter to initially inspect for a crack and to modify the MGB sliding cowling rails. Each 10-hour repetitive inspection will take about 0.25 work-hour. The average labor rate is $85 per work-hour and required parts will cost about $1,793 per helicopter. Based on these figures, we estimate the cost of this AD on U.S. operators will be $17,145 or $3,429 per helicopter, assuming 60 repetitive inspections will be performed each year and assuming the entire fleet is modified and no cracks are found.
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 helicopters identified in this rulemaking action.
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 that this AD:
(1) Is not a “significant regulatory action” under Executive Order 12866;
(2) Is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction; 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.
We prepared an economic evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to all Model AS332C, L, and L1 helicopters without modification (MOD) 0722907, except helicopters with serial numbers 2078 and 2102, certificated in any category.
This AD defines the unsafe condition as a crack in the outer skin, butt strap, or fuselage frame, which could result in loss of airframe structural integrity, and subsequent loss of control of the helicopter.
This AD becomes effective May 23, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
(1) Within 10 hours time-in-service (TIS) for helicopters that have 8,800 or more hours TIS or before or upon reaching 8,810 hours TIS for helicopters that have less than 8,800 hours TIS, and thereafter at intervals not to exceed 10 hours TIS, visually inspect for a crack on the outer skin and the butt strap in the sliding cowling right-hand and left-hand rail attachment areas on Frame 5295 as shown in Figure 2 of Eurocopter Alert Service Bulletin No. 05.00.76, Revision 0, dated February 20, 2008 (ASB).
(i) If there is a crack in the outer skin or in the butt strap per paragraph (e)(1) of this AD, before further flight, inspect for a crack in Frame 5295 in the areas shown in Figure 3, Area 1, and Figure 4, of the ASB.
(ii) If there is a crack in the outer skin, the butt strap, or in Frame 5295 in the areas inspected as required by this AD, before further flight, repair the part in accordance with a method approved by the FAA.
(2) Within 300 hours TIS, for each helicopter that has 8,800 or more hours TIS, modify the sliding cowling rails and shims in the attachment areas on Frame 5295 (corresponds to MOD 0726478R2), as depicted in Figure 5 and by following the Accomplishment Instructions, paragraph 2.B.3., of the ASB.
A special flight permit is permitted for a helicopter with a crack in the outer skin or butt strap to operate the helicopter to a location where the requirements of this AD can be accomplished. A special flight permit is not permitted for a helicopter with a crack in Frame 5295.
(1) The Manager, Safety Management Group, FAA, may approve AMOCs for this AD. Send your proposal to: Gary Roach, Aviation Safety Engineer, Regulations and Policy Group, Rotorcraft Directorate, FAA, 2601 Meacham Blvd., Fort Worth, Texas 76137; telephone (817) 222–5110; email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office, before operating any aircraft complying with this AD through an AMOC.
The subject of this AD is addressed in European Aviation Safety Agency (France) AD No. 2008–0035–E, dated February 21, 2008.
Joint Aircraft Service Component (JASC) Code: 5311, Fuselage, Main Frame.
(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) Eurocopter Alert Service Bulletin No. 05.00.76, Revision 0, dated February 20, 2008.
(ii) Reserved.
(3) For Eurocopter service information identified in this AD, contact American Eurocopter Corporation, 2701 N. Forum Drive, Grand Prairie, Texas 75052; telephone (972) 641–0000 or (800) 232–0323; fax (972) 641–3775; or at
(4) You may view this service information at FAA, Office of the Regional Counsel, Southwest Region, 2601 Meacham Blvd., Room 663, Fort Worth, Texas 76137. For information on the availability of this material at the FAA, call (817) 222–5110.
(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 (202) 741–6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for certain The Boeing Company Model 777–200, –200LR, –300, –300ER, and 777F series airplanes. This AD was prompted by a report that during a test of the oxygen system, an operator found that the passenger oxygen masks did not properly flow oxygen, and that a loud noise occurred in the overhead area, which was caused by the flex line separating from the hard line due to a missing clamshell coupler. This AD requires, for certain airplanes, performing a detailed inspection of certain areas of the airplane oxygen system to ensure clamshell couplers are installed and fully latched, and corrective actions if necessary. For all airplanes, this AD requires performing and meeting the requirements of the low pressure leak test. We are issuing this AD to prevent the oxygen system flex line from separating from the hard line, which could cause an oxygen leak and a drop in the oxygen system pressure, resulting in improper flow of oxygen through the passenger masks and injury to passengers if emergency oxygen is needed.
This AD is effective May 23, 2013.
The Director of the Federal Register approved the incorporation by reference of a certain publication listed in the AD as of May 23, 2013.
For service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, P.O. Box 3707, MC 2H–65, Seattle, Washington 98124–2207; telephone 206–544–5000, extension 1; fax 206–766–5680; Internet
You may examine the AD docket on the Internet at
Susan Monroe, Aerospace Engineer, Cabin Safety and Environmental Systems Branch, ANM–150S, FAA, Seattle Aircraft Certification Office, 1601 Lind Avenue SW., Renton, WA 98057–3356; phone: 425–917–6457; fax: 425–917–6590; email:
We issued a Notice of Proposed Rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM published in the
We gave the public the opportunity to participate in developing this AD. The Boeing Company and Kristopher Charles Kleiner supported this final rule. The following presents the comment received on the NPRM (77 FR 55768, September 11, 2012) and the FAA's response to the comment.
Air New Zealand requested clarification of Note 1 to paragraph (i) of the NPRM (77 FR 55768, September 11, 2012). Air New Zealand asked if the FAA intended to state a specific revision for the installation of the clamshell coupler in Subject 35–00–00, Oxygen, of Chapter 35, Oxygen, of Part II, Practices and Procedures, of the Boeing 777 Aircraft Maintenance Manual, Revision 65, dated May 5, 2012, knowing that it will be revised within the time frame of this NPRM. Air New Zealand also asked if an alternative method of compliance (AMOC) will be required if an operator intends to use a later revision of the maintenance manual.
We agree to provide clarification of Note 1 to paragraph (i) of the NPRM (77 FR 55768, September 11, 2012). Note 1 to paragraph (i) of the NPRM is provided as guidance and is not an AD requirement; therefore, approval of an AMOC will not be required for using later revisions of the maintenance manual. Since we issued the NPRM, the aircraft maintenance manual has been revised. We have updated Note 1 to paragraph (i) of this AD with the latest revision. We have changed this AD accordingly.
We reviewed the relevant data, considered the comment received, and determined that air safety and the public interest require adopting the AD with the change described previously—and minor editorial changes. We have determined that these minor changes:
• Are consistent with the intent that was proposed in the NPRM (77 FR 55768, September 11, 2012) for correcting the unsafe condition; and
• Do not add any additional burden upon the public than was already proposed in the NPRM (77 FR 55768, September 11, 2012).
We also determined that these changes will not increase the economic burden on any operator or increase the scope of the AD.
We estimate that this AD affects 6 airplanes of U.S. registry.
We estimate the following costs to comply with this AD:
We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this AD.
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.
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 that this AD:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under 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.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD is effective May 23, 2013.
None.
This AD applies to The Boeing Company Model 777–200, –200LR, –300, –300ER, and 777F series airplanes; certificated in any category; as identified in Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011.
Joint Aircraft System Component (JASC)/Air Transport Association (ATA) of America Code 35, Oxygen.
This AD was prompted by a report that during a test of the oxygen system, an operator found that the passenger oxygen masks did not properly flow oxygen and that a loud noise occurred in the overhead area, which was caused by the flex line separating from the hard line due to a missing clamshell coupler. We are issuing this AD to prevent the oxygen system flex line from separating from the hard line, which could cause an oxygen leak and a drop in the oxygen system pressure, resulting in improper flow of oxygen through the passenger masks and injury to passengers if emergency oxygen is needed.
Comply with this AD within the compliance times specified, unless already done.
Within 36 months after the effective date of this AD, do the applicable actions in paragraph (g)(1) or (g)(2) of this AD.
(1) For Groups 1–6, 8, and 9 airplanes, as identified in Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011: Do a detailed inspection of certain areas of the airplane oxygen system to ensure clamshell couplers are installed and fully latched, and perform and meet the requirements of the low pressure leak test, in accordance with the Accomplishment Instructions of Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011.
(2) For Group 7 airplanes, as identified in Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011: Perform and meet requirements of the low pressure leak test, in accordance with the Accomplishment Instructions of Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011.
If, during any inspection required by paragraph (g) of this AD, any clamshell coupler is not fully latched: Before further flight, latch the clamshell coupler, in accordance with the Accomplishment Instructions of Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011.
If, during any inspection required by paragraph (g) of this AD, any clamshell coupler is not installed: Before further flight, install a clamshell coupler.
Guidance on installation of the clamshell coupler may be found in Subject 35–00–00, Oxygen, of Chapter 35, Oxygen, of Part II, Practices and Procedures, of the Boeing 777 Aircraft Maintenance Manual, Revision 67, dated January 5, 2013.
(1) The Manager, Seattle Certification Office (ACO), FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the manager of the ACO, send it to the attention of the person identified in the Related Information section of this AD. Information may be emailed to:
(2) Before using any approved AMOC, notify your appropriate principal inspector,
For more information about this AD, contact Susan Monroe, Aerospace Engineer, Cabin Safety and Environmental Systems Branch, ANM–150S, FAA, Seattle Aircraft Certification Office, 1601 Lind Avenue SW., Renton, WA 98057–3356; phone: 425–917–6457; fax: 425–917–6590; email:
(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) Boeing Special Attention Service Bulletin 777–35–0024, dated September 1, 2011.
(ii) Reserved.
(3) For Boeing service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, P.O. Box 3707, MC 2H–65, Seattle, Washington 98124–2207; telephone 206–544–5000, extension 1; fax 206–766–5680; Internet
(4) You may review copies of the referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, Washington. For information on the availability of this material at the FAA, call 425–227–1221.
(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 202–741–6030, or go to:
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Final rule.
We are adopting a new airworthiness directive (AD) for Grob-Werke Model G115EG 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 cracks in the elevator trim tab arms on several Grob G 115 airplanes, which could result in failure of the part and consequent loss of control. We are issuing this AD to require actions to address the unsafe condition on these products.
This AD is effective May 23, 2013.
The Director of the Federal Register approved the incorporation by reference of a certain publication listed in the AD as of May 23, 2013.
You may examine the AD docket on the Internet at
For service information identified in this AD, contact Grob Aircraft AG, Lettenbachstrasse 9, D–86874 Tussenhausen-Mattsies, Germany; telephone: +49 (0) 8268 998 139; fax: +49 (0) 8268 998 200; email:
Taylor Martin, Aerospace Engineer, FAA, Small Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329–4138; fax: (816) 329–4090; email:
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
On several Grob G 115 aeroplanes, elevator trim tab arms Part Number (P/N) 115E–3758 have been found cracked, from a rear mounting hole (either L/H or R/H) to the rear edge of the trim tab arm.
This condition, if not detected and corrected, could lead to further crack propagation, possibly resulting in failure of the part and consequent loss of control of the aeroplane.
For the reasons described above, this AD requires repetitive inspections of the elevator trim tab arm to detect cracks and, if detected, replacement of the part with a serviceable part.
This AD also provides an optional terminating action for the repetitive inspections.
The Model G115EG airplane is the only airplane type-certificated in the United States with the same part numbers and similar configuration as the airplane model described in the MCAI.
We gave the public the opportunity to participate in developing this AD. We received no comments on the NPRM (78 FR 2910, January 15, 2013) or on the determination of the cost to the public.
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 (78 FR 2910, January 15, 2013) for correcting the unsafe condition; and
• Do not add any additional burden upon the public than was already proposed in the NPRM (78 FR 2910, January 15, 2013).
We estimate that this AD will affect 0 products of U.S. registry. We also estimate that it would take about 3 work-hours per product to comply with the basic requirements of this AD. The average labor rate is $85 per work-hour. Required parts would cost about $372 per product.
Based on these figures, we estimate the cost of this AD on U.S. operators to be $627 per product.
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.
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.
You may examine the AD docket on the Internet at
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This airworthiness directive (AD) becomes effective May 23, 2013.
None.
This AD applies to GROB–WERKE G115EG airplanes, all serial numbers, certificated in any category.
Air Transport Association of America (ATA) Code 55: Stabilizers.
This AD was prompted by the discovery of cracks in the elevator trim tab arms on several Grob G 115 airplanes, which could result in failure of the part and consequent loss of control. The Model G115EG airplane is the only airplane type-certificated in the United States with the same part numbers and similar configuration as the airplane model described in the MCAI. We are issuing this proposed AD to detect cracks and prevent the part from failing.
Unless already done, do the following actions following Grob Aircraft Service Bulletin No. MSB1078–186/3, dated August 3, 2012.
(1) Within the next 50 hours time-in-service (TIS) after May 23, 2013 (the effective date of this AD) and repetitively thereafter at intervals not to exceed 200 hours TIS, inspect both left hand (L/H) and right hand (R/H) elevator trim tab arms, part number (P/N) 115E–3758, using a nondestructive testing (NDT) method such as a dye-penetrant or eddy-current that is beyond just a visual inspection.
(2) If during any inspection required in paragraph (f)(1) of this AD a crack is found, before further flight, replace the affected elevator trim tab arm with P/N 115E–3758/1. The replacement of an elevator trim tab arm with P/N 115E–3758/1 will terminate the repetitive inspection requirement for that trim tab arm. Replacement of both R/H and L/H trim tab arms with P/N 115E–3758/1 will terminate the repetitive requirement in paragraph (f)(1) of this AD.
(3) Replacement at any time of an elevator trim tab arm with P/N 115E–3758/1 will terminate the repetitive requirement in paragraph (f)(1) of this AD for that elevator trim tab arm. Replacement of both R/H and L/H trim tab arms with P/N 115E–3758/1 will terminate the repetitive requirement in paragraph (f)(1) of this AD.
This AD provides credit for the actions required in this AD if already done before the effective date of this AD following Grob Aircraft Service Bulletin No. MSB1078–186/2, dated March 28, 2012; Grob Aircraft Service Bulletin No. MSB1078–186/1, dated March 8, 2012; or Grob Aircraft Service Bulletin No. MSB1078–186, dated February 15, 2012.
The following provisions also apply to this AD:
(1)
(2)
(3)
Refer to MCAI European Aviation Safety Agency (EASA) AD No.: 2012–0155, dated August 20, 2012; Grob Aircraft Service Bulletin No. MSB1078–186/2, dated March 28, 2012; Grob Aircraft Service Bulletin No. MSB1078–186/1, dated March 8, 2012; or Grob Aircraft Service Bulletin No. MSB1078–
(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) Grob Aircraft Service Bulletin No. MSB1078–186/3, dated August 3, 2012.
(ii) Reserved.
(3) For Grob Aircraft AG service information identified in this AD, contact Grob Aircraft AG, Lettenbachstrasse 9, D–86874 Tussenhausen-Mattsies, Germany; phone: +49 (0) 8268 998 139; fax: +49 (0) 8268 998 200; email:
(4) You may view this service information at 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.
(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 202–741–6030, or go to:
Federal Aviation Administration (FAA), DOT.
Final rule.
We are adopting a new airworthiness directive (AD) for Bell Model 430 helicopters, which requires replacing certain components of the air data system. This AD was prompted by the discovery of incorrect indicated airspeed when the helicopter was tested to the cold temperature limits (−40 degrees centigrade) required for Category A operations. The actions of this AD are intended to correct the published Vne and to correct the indicated airspeed.
This AD is effective May 23, 2013.
For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4, telephone (450) 437–2862 or (800) 363–8023, fax (450) 433–0272, or
You may examine the AD docket on the Internet at
Mark F. Wiley, Aviation Safety Engineer, FAA, Rotorcraft Directorate, Regulations and Policy Group, 2601 Meacham Blvd., Fort Worth, Texas 76137, telephone (817) 222–5110, fax (817) 222–5110, email
On October 22, 2012, at 77 FR 64439, the
The Transport Canada Civil Aviation (TCCA), which is the aviation authority for Canada, has issued Canadian AD No. CF–2005–30, dated August 3, 2005, to correct an unsafe condition for the Bell Model 430 helicopters. Discrepancies in the processing and display of air data were revealed when testing at low temperatures to minus 40 degrees Centigrade (−40°C). The TCCA advises that modification to the instrumentation is required to reflect the Vne airspeed values tested at temperatures to −40°C. The TCCA states “This modification affects the software in the Vne Overspeed Warning computer (required for Category A operations) and in the AFCS [Automatic Flight Control System] Air Data Computer.” TCAA issued AD CF–2005–30 to require the procedures in Bell Alert Service Bulletin (ASB) No. 430–05–35, dated June 21, 2005, for replacing the affected instruments. Bell also issued ASB No. 430–01–22, dated April 30, 2001 (ASB 430–01–22), which provided a temporary Rotorcraft Flight Manual Supplement and placards with information on airspeed corrections. TCCA did not issue an AD to mandate the provisions of ASB 430–01–22.
We gave the public the opportunity to participate in developing this AD, but we did not receive any comments on the NPRM (77 FR 64439, October 22, 2012).
These helicopters have been approved by the TCCA and are approved for operation in the United States. Pursuant to our bilateral agreement with Canada, TCCA has notified us of the unsafe condition described in the Canadian AD.
We are issuing this AD because we evaluated all information provided by TCCA and determined the unsafe condition exists and is likely to exist or develop on other helicopters of the same type designs and that air safety and the public interest require adopting the AD requirements as proposed.
We do not use the compliance date of July 31, 2007.
We estimate that this AD will affect 52 helicopters of U.S. registry. We estimate that operators may incur the following costs in order to comply with this AD:
• $680 to replace the overspeed warning computer, pilot and copilot airspeed indicators, Vne converter, and AFCS air data computer adapter module for each helicopter, assuming 8 work hours for each helicopter at an average labor rate of $85 per work hour, and
• $46,074 per helicopter for the required parts.
Based on these figures, we estimate the total cost impact of the AD on U.S. operators to be $2,431,208 for the fleet.
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 helicopters identified in this rulemaking action.
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.
(1) Is not a “significant regulatory action” under Executive Order 12866;
(2) Is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);
(3) Will not affect intrastate aviation in Alaska to the extent that it justifies making a regulatory distinction; 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.
We prepared an economic evaluation of the estimated costs to comply with this AD and placed it in the AD docket.
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to Model 430 helicopters: serial number (S/N) 49001 through 49103, with Overspeed Warning Kit, part number (P/N) 430–706–004–101 or P/N 430–706–004–103, installed; S/N 49001 through 49100, with Single Automatic Flight Control System (AFCS) with Flight Director Kit, P/N 430–705–009–103, –105, –109, –111, –115, –117, or P/N 430–705–011–109, –111, –121, or –123, installed; and S/N 49001 through 49100, with Dual AFCS with Flight Director Kit, P/N 430–705–011–103, –105, –115, –117, –125, –127, –129, –133, –135, or –137, installed, certificated in any category.
This AD defines the unsafe condition as inability of the helicopters, based on testing, to operate at the published V
This AD becomes effective May 23, 2013.
You are responsible for performing each action required by this AD within the specified compliance time unless it has already been accomplished prior to that time.
Within 1 year:
(1) For helicopters with an Overspeed Warning System, replace the Overspeed Warning Computer, P/N 430–375–013–103, with the Overspeed Warning Computer, P/N 430–375–013–105; the V
(i) If installed, remove the decal, P/N 430–075–070–103, from below the pilot and copilot airspeed indicators;
(ii) Leak test the pilot pitot static system; and
(iii) Operationally test the overspeed warning system.
(2) For helicopters with a Single or Dual AFCS with a Flight Director, replace the AFCS Air Data Computer Adapter Module, P/N 065–05041–0021, with P/N 065–05041–0031;
(i) If installed, remove the decal, P/N 430–075–070–101, from above the pilot and copilot electronic attitude direction indicators airspeed indicators;
(ii) Leak test the pilot pitot static system;
(iii) Power-up test the altimeter/vertical speed indicator (ALT/VSI) and self-test the ALT/VSI of the AFCS air data computer.
(1) The Manager, Rotorcraft Standards Staff, FAA may approve AMOCs for this AD. Send your proposal to: Mark F. Wiley, Aviation Safety Engineer, Rotorcraft Directorate, Regulations and Policy Group, 2601 Meacham Blvd., Fort Worth, Texas 76137, telephone (817) 222–5110, fax (817) 222–5961, email
(2) For operations conducted under a 14 CFR part 119 operating certificate or under 14 CFR part 91, subpart K, we suggest that you notify your principal inspector, or lacking a principal inspector, the manager of the local flight standards district office or certificate holding district office before operating any aircraft complying with this AD through an AMOC.
(1) Bell Helicopter Textron Alert Service Bulletin (ASB) No. 430–05–35, dated June 21, 2005, and ASB No. 430–01–22, dated April 30, 2001, which are not incorporated by reference, contain additional information about the subject of this AD. For service information identified in this AD, contact Bell Helicopter Textron Canada Limited, 12,800 Rue de l'Avenir, Mirabel, Quebec J7J1R4, telephone (450) 437–2862 or (800) 363–8023, fax (450) 433–0272, or
(2) The subject of this AD is addressed in Transport Canada Civil Aviation AD No. CF 2005–30, dated August 3, 2005.
Joint Aircraft System/Component Code: 3417 Air Data Computer.
Internal Revenue Service (IRS), Treasury.
Final and temporary regulations.
This document contains final regulations relating to reporting by brokers for transactions involving debt instruments and options. These final regulations reflect changes in the law made by the Energy Improvement and Extension Act of 2008 that require brokers when reporting the sale of securities to the IRS to include the customer's adjusted basis in the sold securities and to classify any gain or loss as long-term or short-term. These final regulations also implement the requirement that a broker report gross proceeds from a sale or closing transaction with respect to certain options. In addition, this document contains final regulations that implement reporting requirements for a transfer of a debt instrument or an option to another broker and for an organizational action that affects the basis of a debt instrument or an option. Moreover, this document contains final regulations relating to the filing of Form 8281, “Information Return for Publicly Offered Original Issue Discount Instruments,” for certain debt instruments with original issue discount and temporary regulations relating to information reporting for premium. The text of the temporary regulations in this document also serves as the text of the proposed regulations (REG–154563–12) set forth in the Proposed Rules section in this issue of the
Pamela Lew of the Office of Associate Chief Counsel (Financial Institutions and Products) at (202) 622–3950 (not a toll-free number).
The collection of information contained in these final regulations related to the furnishing of information in connection with the transfer of securities has been reviewed and approved by the Office of Management and Budget in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)) under control number 1545–2186. The collection of information in these final regulations in §§ 1.6045–1(c)(3)(xi)(C) and 1.6045A–1 is necessary to allow brokers that effect sales of transferred covered securities to determine and report the adjusted basis of the securities and whether any gain or loss with respect to the securities is long-term or short-term in compliance with section 6045(g) of the Internal Revenue Code (Code). This collection of information is required to comply with the provisions of section 403 of the Energy Improvement and Extension Act of 2008, Division B of Public Law 110–343 (122 Stat. 3765, 3854 (2008)) (the Act).
In addition, the collection of information contained in § 1.6045–1(n)(5) of these final regulations related to the furnishing of information in connection with the sale or transfer of a debt instrument that is a covered security is an increase in the total annual burden under control number 1545–2186. Under section 6045(g), a broker is required to determine and report the adjusted basis upon the sale or transfer of a debt instrument that is a covered security. If a sale has occurred, a broker must also determine and report whether any gain or loss with respect to the debt instrument is long-term or short-term in compliance with section 6045(g). The holder of a debt instrument is permitted to make a number of elections that affect how basis is computed. To minimize the need for reconciliation between information reported by a broker to both a customer and the IRS and the amounts reported on the customer's tax return, a broker is required to take into account certain specified elections in reporting information to the customer. A customer, therefore, must provide certain information concerning an election to the broker in a written notification, which includes a writing in electronic format. The adjusted basis information will be used for audit and examination purposes. The likely respondents are recipients of Form 1099–B.
Estimated total annual reporting burden is 1,417 hours.
Estimated average annual burden per respondent is 0.12 hours.
Estimated average burden per response is 7 minutes.
Estimated number of respondents is 11,500.
Estimated total frequency of responses is 11,500.
The burden for the collection of information contained in the amendment to § 1.1275–3 will be reflected in the burden on Form 8281, “Information Return for Publicly Offered Original Issue Discount Instruments,” when revised to request the additional information in the regulations. The burden for the collection of information contained in the other amendments to § 1.6045–1 will be reflected in the burden on Form 1099–B, “Proceeds from Broker and Barter Exchange Transactions,” when revised to request the additional information in the regulations. The burden for the collection of information contained in the amendments to § 1.6045B–1 will be reflected in the burden on Form 8937, “Report of Organizational Actions Affecting Basis of Securities,” when revised to request the additional information in the regulations. The burden for the collection of information contained in § 1.6049–9T will be reflected in the burdens on Form 1099–INT and Form 1099–OID when revised to request the additional information in the regulations. The information described in this paragraph is required to enable the IRS to verify that a taxpayer is reporting the correct amount of income or gain or claiming the correct amount of losses or deductions.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid control number assigned by the Office of Management and Budget.
Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
This document contains amendments to the Income Tax Regulations (26 CFR part 1) relating to information reporting by brokers and others as required by section 6045 of the Code. This section
On November 25, 2011, the Treasury Department and the IRS published in the
After considering the comments, the Treasury Department and the IRS adopt the proposed regulations as amended by this Treasury decision. The comments and revisions are discussed in this preamble.
The proposed regulations had a proposed effective date for both debt instruments and options of January 1, 2013. The Treasury Department and the IRS received numerous requests to delay the proposed effective dates for both debt instruments and options. Brokers and other interested parties maintained that the proposed effective date of January 1, 2013, did not provide them sufficient time to build and test the systems required to implement the reporting rules for debt instruments and options. In response to these requests, Notice 2012–34 (2012–21 I.R.B. 937) was issued to announce that the effective dates in the final regulations would be postponed to January 1, 2014.
A number of commenters also requested relief related to various aspects of reporting under sections 6045, 6045A, and 6045B. One commenter requested a 36-month general penalty relief period to allow brokers to test and refine their reporting systems.
In response to these comments, as was announced in Notice 2012–34, the effective date of these final regulations is postponed so that basis reporting is required for debt instruments and options no earlier than January 1, 2014. Moreover, these final regulations implement the reporting requirements for debt instruments in phases, as described in more detail later in this preamble. These final regulations also implement transfer reporting in phases. These features of the regulations are intended to give brokers ample time to develop and implement reporting systems.
Another commenter requested a safe-harbor for good faith reliance upon debt instrument data that is provided by third-party vendors for purposes of both basis and transfer reporting. With respect to information from third-party vendors, §§ 1.6045–1(d)(2)(iv)(B) and 1.6045A–1(b)(8)(ii) of the 2010 final regulations provide that a broker is deemed to rely upon the information provided by a third party in good faith if the broker neither knows nor has reason to know that the information is incorrect (§ 1.6045A–1(b)(8)(ii) is redesignated in these final regulations as § 1.6045A–1(b)(11)(ii)). Therefore, because the 2010 final regulations already address the concerns raised by these comments, no change on this issue is needed in these final regulations.
Several commenters requested a safe-harbor for purposes of both basis and transfer reporting for good faith reliance upon information received on a section 6045A transfer statement. With respect to basis reporting, § 1.6045–1(d)(2)(iv)(A) of the 2010 final regulations provides for penalty relief if a broker relies upon transferred information when preparing a return under section 6045. With respect to transfer reporting, § 1.6045A–1(b)(8)(i) of the 2010 final regulations (redesignated in these final regulations as § 1.6045A–1(b)(11)(i)) provides for penalty relief if a broker relies upon transferred information when preparing a transfer statement under section 6045A. Because the 2010 final regulations already address the concerns raised by these comments, no change on this issue is needed in these final regulations.
The proposed regulations required basis reporting for all debt instruments, other than a debt instrument subject to section 1272(a)(6) (in general, a debt instrument with principal subject to acceleration). Numerous commenters requested that the final regulations narrow the scope of basis reporting for debt instruments. Many commenters requested permanent exemptions from basis reporting for debt instruments that the commenters believe present data collection or computational difficulties, including convertible debt instruments, debt instruments denominated in non-U.S. dollar currencies, contingent payment debt instruments, variable rate debt instruments, municipal obligations, tax credit bonds, payment-in-kind (PIK) bonds, certificates of deposit, debt instruments issued by foreign persons, U.S. Treasury strips and other stripped debt instruments, inflation-indexed debt instruments, privately placed debt instruments, commercial paper, hybrid securities, investment units, debt instruments subject to put or call options, debt instruments with stepped interest rates, factored bonds, and short-term debt instruments. Alternatively, some commenters suggested that basis reporting be deferred for debt instruments until data is more readily available for some of the instruments described in the preceding sentence. One commenter renewed a request for exempting corporate trustees from basis reporting for registered debt instruments issued in a physical form. Some commenters asked for a permanent exemption or deferred reporting for debt instruments because, unlike the rules for equity, there are numerous rules in the Code and regulations, including holder elections, that affect the adjusted basis of a debt instrument, such as the rules relating to original issue discount (OID), bond premium, market discount, and acquisition premium.
Several commenters requested that the final regulations provide a specific list of the debt instruments subject to basis reporting rather than a list of the debt instruments not subject to basis reporting. Other commenters suggested limiting basis reporting to a debt instrument that has a fixed yield and fixed maturity date. One commenter indicated that fixed yield, fixed maturity date debt instruments comprise approximately 90% of the reportable debt instrument transactions.
Section 6045(g) by its terms requires basis reporting by brokers with respect to any note, bond, debenture, or other
For a debt instrument with less complex features, these final regulations require basis reporting by a broker if the debt instrument is acquired on or after January 1, 2014, consistent with Notice 2012–34. This category of less complex debt instruments includes a debt instrument that provides for a single fixed payment schedule for which a yield and maturity can be determined for the instrument under § 1.1272–1(b), a debt instrument that provides for alternate payment schedules for which a yield and maturity can be determined for the instrument under § 1.1272–1(c) (such as a debt instrument with an embedded put or call option), and a demand loan for which a yield can be determined under § 1.1272–1(d). Commenters requested delayed reporting for any debt instrument with an embedded put or call option. The Treasury Department and the IRS believe that brokers should be able to implement reporting for a debt instrument with an embedded option that entitles the issuer to call or the holder to put the debt instrument prior to its scheduled maturity. Moreover, because an embedded put or call option is a common feature of debt instruments, delaying basis reporting for debt instruments with such a feature could delay basis reporting for an unduly large proportion of debt instruments.
Some debt instruments with a fixed yield and a fixed maturity date nevertheless pose challenges for information reporting. For these debt instruments and for more complex debt instruments that do not have a fixed yield and a fixed maturity date, these final regulations require basis reporting for debt instruments acquired on or after January 1, 2016. The Treasury Department and the IRS believe that brokers may need additional time to implement basis reporting for these debt instruments because of their more complex features or the lack of public information for the debt instruments. Fixed yield, fixed maturity debt instruments that are subject to reporting if they are acquired on or after January 1, 2016, include a debt instrument that provides for more than one rate of stated interest (such as a debt instrument with stepped interest rates), a convertible debt instrument, a stripped bond or coupon, a debt instrument that requires payment of either interest or principal in a non-U.S. dollar currency, certain tax credit bonds, a debt instrument that provides for a PIK feature, a debt instrument issued by a non-U.S. issuer, a debt instrument for which the terms of the instrument are not reasonably available to the broker within 90 days of the date the debt instrument was acquired by the customer, a debt instrument that is issued as part of an investment unit, and a debt instrument evidenced by a physical certificate unless such certificate is held (whether directly or through a nominee, agent, or subsidiary) by a securities depository or by a clearing organization described in § 1.1471–1(b)(18). Other debt instruments that do not have a fixed yield and fixed maturity date but are subject to reporting if they are acquired on or after January 1, 2016, include a contingent payment debt instrument, a variable rate debt instrument, and an inflation-indexed debt instrument.
As noted earlier in this preamble, due to the difficulties in implementing basis reporting, the proposed regulations provided that a debt instrument described in section 1272(a)(6) (in general, a debt instrument with principal subject to acceleration) would not be subject to basis reporting. In response to favorable comments on this exception, these final regulations retain this exception from basis reporting.
A number of commenters requested delayed reporting or no basis reporting for short-term debt instruments (that is, debt instruments with a fixed maturity date not more than one year from the date of issue). One commenter argued that the application of the OID, bond premium, market discount, and acquisition premium rules to a short-term debt instrument, including the numerous elections applicable to short-term debt instruments, is complicated, that the effects on the basis of a short-term debt instrument would be marginal, and that basis reporting for short-term debt instruments may impose a significant burden on brokers and provide little benefit to taxpayers or the IRS. Because the Treasury Department and the IRS agree with this comment, these final regulations except short-term debt instruments from basis reporting.
Another commenter requested that the rules pertaining to short-term debt instruments be extended to all debt instruments that are acquired with a remaining term of one year or less. This exemption from information reporting would apply to a debt instrument originally issued with a term of greater than one year and acquired in a secondary market purchase when there is a remaining term of one year or less. The request to extend the short-term debt instrument rules to a long-term debt instrument with one year or less until maturity is not adopted because the rules that govern a debt instrument with a term over one year do not change when the maturity has declined to one year or less. While the potential for significant gain or loss on the debt instrument usually diminishes in the final year, the reporting is useful to the customer and the IRS, and all information required for reporting will be available to the broker.
One commenter requested that the final regulations exempt from reporting securities issued in connection with a bankruptcy restructuring because it is not always clear if a particular security is a debt instrument. After consideration of the comment, this request was not adopted because these final regulations provide that a security is treated as debt for reporting purposes only if the issuer has classified the security as debt or, if the issuer has not classified the security, if the broker knows that the security is reasonably classified as debt under general Federal tax principles.
A number of commenters raised concerns and suggestions about how to make reporting more consistent, both between transferring and receiving brokers and between brokers and customers. Many commenters expressed a strong desire to ensure that a customer who transfers a security from one broker to another will receive consistent reporting from the two brokers. Many commenters also asked for assistance in minimizing the amount of potential reconciliation between an amount reported by a broker to a customer and the IRS and the amount reported by that customer on a tax return.
The proposed regulations attempted to simplify reporting requirements by specifying the elections brokers were to assume to compute OID, market discount, bond premium, and acquisition premium reported to holders, and not permitting brokers to support alternative customer elections. A number of commenters, however, indicated a desire by brokers to support debt instrument elections made by their customers rather than rely on assumptions provided in the
However, other commenters indicated that some of the statutory defaults were generally simpler to apply and produced economic results that were only negligibly different than the defaults prescribed by the proposed regulations. For example, while the proposed regulations would have required reporting of market discount using a constant yield method, several commenters indicated a preference for reporting accrued market discount using a straight line method.
The Treasury Department and the IRS also received comments regarding the treatment of amortizable bond premium under section 171. One commenter requested that the section 171 election not be mandatory for reporting purposes because most taxpayers have not made the election, but suggested that a broker be required to support the section 171 election if a customer informs the broker that the election was or will be made.
After consideration of all the comments, the Treasury Department and the IRS have concluded that the best way to balance certainty and flexibility is to require brokers to report information using the default assumptions provided in the relevant statute and regulations, except in the case of the section 171 election, but to require brokers to accommodate elections by taxpayers that choose to depart from the defaults. Under these final regulations, upon written notification by a customer, a broker must take into account the following elections for basis reporting purposes: the election to accrue market discount using a constant yield; the election to include market discount in income currently; the election to treat all interest as OID; and the spot rate election for interest accruals with respect to a covered debt instrument denominated in a currency other than the U.S. dollar. The Treasury Department and the IRS do not anticipate that many taxpayers will make these elections. As a practical matter, by removing short-term debt instruments from the basis reporting rules, the number of elections available for a covered security has been reduced to a manageable number, and it is reasonable to require that the remaining debt instrument elections be supported.
These final regulations make an exception to the general rule requiring brokers to use the default elections provided in the statute and regulations in the case of bond premium. Section 171 generally requires taxpayers to affirmatively elect to amortize bond premium on taxable bonds, which then offsets interest income on the bond. Except in the rare case of a holder that prefers a capital loss, the election to amortize bond premium generally will benefit the holder of a debt instrument. Thus, consistent with the proposed regulations, these final regulations require brokers to assume that customers have made the election to amortize bond premium provided in section 171 when reporting basis, unless the customer has notified the broker otherwise.
The rules regarding basis reporting for bond premium in the proposed regulations prompted a number of commenters to request that the rules for reporting interest income associated with a bond acquired at a premium be conformed to the rules regarding basis reporting for these same debt instruments. In response to these commenters, this document contains temporary regulations addressing reporting of premium under section 6049. See Part H of this preamble for additional discussion of this issue.
The Treasury Department and the IRS considered making broker support of debt instrument elections a permitted, but not required, activity, but the additional administrative problems that can arise if a transferring broker supports certain elections while the receiving broker does not support the same elections made a permissive approach problematic. For example, if the receiving broker did not support the same elections as the transferring broker, and the customer properly made one of the elections permitted with respect to a debt instrument and notified the transferring broker of the election, the information provided by the receiving broker on the relevant Form 1099 would not reflect the customer's election, requiring the customer to provide a reconciliation on the customer's income tax return. These administrative problems lead to the conclusion that brokers should be required to support either all of the permitted elections for debt instruments or none of them. Given the numerous requests to support customer elections, coupled with requests to reduce the need for a customer to reconcile tax return data to the data provided by a broker, the Treasury Department and the IRS decided that support for customer debt instrument elections would be beneficial to taxpayers and would not impose an undue burden on brokers. It should be noted that supporting customer elections will require additional transfer statement information to advise a receiving broker of any elections that were used to compute the information provided.
Several commenters pointed out that brokers do not necessarily use common terms or conventions for debt instrument computations. For example, 30 days per month/360 days per year, actual days per month/360 days per year, and actual days per month/365 days per year are possible interest computation day count conventions. Different brokers may use different amortization and accretion assumptions, different accrual periods, and different rounding conventions.
The proposed regulations prescribed conventions to determine the accrual period to be used for reporting purposes. These final regulations generally adopt the conventions in the proposed regulations. Under these final regulations, a broker must use the same accrual period that is used to report OID or stated interest to a customer under section 6049. In any other situation, a broker is required to use a semi-annual accrual period unless the debt instrument provides for scheduled payments of principal or interest at regular intervals of less than six months over its term, in which case a broker must use an accrual period equal in length to this shorter interval. In response to a comment, these final regulations use a semi-annual accrual period rather than an annual accrual period as the default accrual period.
These final regulations do not prescribe a particular day count convention brokers must use for basis reporting. Instead, these final regulations provide that a broker may use any reasonable day count convention. The terms of a debt instrument, however, generally include
Commenters also indicated disagreement on the effect of puts and calls on calculations associated with a debt instrument. One commenter asked for clarification about whether issuer choice or holder choice will govern the treatment of put and call dates and recommended amortizing all callable debt instruments to their maturity dates rather than call dates. Another commenter requested standardizing the deemed maturity date and limiting the application of the put/call rules to cases in which the broker has actual knowledge of payment terms that could result in a different maturity date if the put/call rules are applied.
These final regulations continue the approach taken in the proposed regulations. The basis reporting rules are not intended to, and do not, change the substantive rules applicable to debt instruments. Thus, when assessing the effect of an embedded put or call option on a debt instrument, a broker must apply the rules described in § 1.1272–1(c)(5) or § 1.171–3(c)(4), whichever is applicable, to determine the correct date to be used in accrual calculations. The rules described in § 1.1272–1(c)(5) have been in effect since 1994 and the rules described in § 1.171–3(c)(4) have been in effect since 1997. Both rules provide a clear and workable framework for determining the effect, if any, of an embedded put or call option on a debt instrument.
One commenter requested that, to the extent brokers are not required to report using a single set of assumptions and computation conventions, explicit language should be added to the regulations covering transfer statements to require transfer of all information needed for a receiving broker to compute adjustments in a manner consistent with the transferor broker, including payment terms and assumptions used by the transferor broker, as well as any taxpayer elections that were supported by the transferor broker. These final regulations adopt this comment by expanding the information that must be included in a transfer statement for a debt instrument.
One commenter stated that there could be problems tracking the adjustments for discount and premium if different measurement periods are used (for example, a daily period versus a period ending on payment dates), especially for a customer that has purchased debt from the same issue at a discount and at a premium. The commenter indicated that tracking OID, market discount, bond premium, and/or acquisition premium adjustments for multiple lots of a single issue will be complex.
One commenter, noting that reporting to the IRS and taxpayers is only required once a year, asked whether a duty exists to compute the debt instrument accruals and display them more frequently than once each year, such as for each accrual or payment period. Another commenter indicated that to facilitate the preparation of transfer statements at any time during a year, it may be necessary to compute all debt instrument accruals each day.
These final regulations generally continue the approach taken in the proposed regulations regarding computations that affect the basis of a debt instrument. In particular, these final regulations do not require a broker to compute debt instrument accruals more than once per year unless a transfer takes place during a tax year, in which case the transferring broker must provide a transfer statement to the receiving broker. If a broker's systems generate more frequent computations to support transfer statements, the broker is permitted to compute the accruals more than once per tax year.
The proposed regulations require accrued market discount to be reported upon the sale of a debt instrument. One commenter asked whether accrued market discount should be reported at the time of a call or at maturity. The commenter also noted that two rules in the proposed regulations relating to market discount may have required the filing of a Form 1099–INT and a Form 1099–B to report accrued market discount. The commenter recommended that accrued market discount be reported only on a Form 1099–B, “Proceeds from Broker and Barter Exchange Transactions,” and associated with a specific sale.
For purposes of section 6045, § 1.6045–1(a)(9) defines a sale to include any disposition of a debt instrument, which includes a retirement of a debt instrument at or prior to its stated maturity. These final regulations do not change this definition of a sale with respect to a debt instrument; however, these final regulations clarify that a sale for purposes of section 6045 includes a partial principal payment. Moreover, under these final regulations, in the case of a sale, accrued market discount will be reported only on the Form 1099–B, which would associate the accrued market discount with a specific sale of a single security. In connection with this comment, these final regulations amend the rule in § 1.6045–1(d)(3) for reporting accrued stated interest on a Form 1099–INT when a debt instrument is sold between interest payment dates to make it clear that the rule does not apply to accrued market discount.
A number of comments were received that address narrower issues. One commenter requested guidance about how to determine and translate interest income or expense (including OID) on certain non-functional currency debt. Rules regarding the determination and translation of interest income and expense on certain debt instruments denominated in a non-functional currency are explicitly addressed in the regulations under section 988.
During the preparation of these final regulations, the Treasury Department and the IRS reviewed the existing reporting requirements for short-term debt instruments. Based on this review, these final regulations exempt from gross proceeds reporting all short-term debt instruments. This exemption is consistent with the existing exemption from reporting for certain short-term debt instruments in § 1.6045–1(c)(3)(vii)(C), and the provisions in these final regulations that exempt short-term debt instruments from basis reporting. Moreover, almost all income related to short-term debt instruments is captured through the income reporting rules under section 6049 and any capital gain or loss related to a short-term debt instrument is expected to be very small.
In general, under the proposed regulations, basis and gross proceeds reporting applied to the following options granted or acquired on or after January 1, 2013: an option on one or more specified securities, including an option on an index substantially all the components of which are specified securities; an option on financial attributes of specified securities, such as interest rates or dividend yields; and a warrant or a stock right on a specified security. The scope provisions in these final regulations are generally the same as the scope provisions in the proposed regulations, except that these final
One commenter asked for clarification of the concept of “financial attributes” in the scope provision. After reviewing the proposed language, the Treasury Department and the IRS believe that the list of items provided in § 1.6045–1(m)(2)(i)(B) provides adequate detail to describe the concept.
Commenters also requested that the regulations not apply to options that are subject to section 1256. As explained immediately below, this comment was not adopted in these final regulations.
Numerous comments were received related to nonequity options that are covered by section 1256(b)(1)(C) (“section 1256 options”), which includes a listed option on a stock index that is not a narrow-based security index. Several commenters noted that the substantive rules that apply to section 1256 options are different from the rules that apply to non-section 1256 options and asked for different reporting treatment for the two types of options. Some commenters requested an exemption from reporting for all section 1256 options. The commenters suggested that if a blanket exemption from reporting is not provided, the IRS should consider extending the reporting rules for regulated futures contracts described in § 1.6045–1(c)(5) to section 1256 options. One commenter noted that although the current rules only require reporting for regulated futures contracts on Form 1099–B, some brokers may already be reporting section 1256 options in a similar manner.
The Treasury Department and the IRS agree that there should be different reporting rules for section 1256 options and non-section 1256 options. In general, an option is subject to reporting under section 6045 only if the option references one or more specified securities. For a nonequity option described in section 1256(b)(1)(C) on one or more specified securities, a broker will apply the reporting rules that apply to a regulated futures contract, which are described in § 1.6045–1(c)(5). For an option on one or more specified securities that is not described in section 1256(b)(1)(C), a broker will report gross proceeds and basis in accordance with the rules in these final regulations for a non-section 1256 option, which are described later in this preamble.
A number of comments focused on potential difficulties in distinguishing between an option on a broad-based index, which would be covered by section 1256, and an option on a narrow-based index, which would be treated in the same manner as an option on a single equity. Commenters requested guidance about how to determine whether an index is broad-based or narrow-based, and some commenters requested that the IRS annually publish a list of what constitutes a section 1256 option. Alternatively, the commenters requested complete exclusion of all stock index options. These final regulations do not provide substantive rules on index options. Rather, to determine whether an index substantially all the components of which are specified securities is a broad-based index under section 1256(g)(6)(B), a broker must look to rules established by the Securities Exchange Commission and the Commodities Futures Trading Commission that determine which regulator has jurisdiction over an option on the index. An option on a broad-based index is a nonequity option described in section 1256(b)(1)(C).
Several commenters requested broker penalty relief for good faith determinations of section 1256 status for index options. The Treasury Department and the IRS appreciate the difficulty in making determinations of section 1256 status. Therefore, these final regulations grant relief under sections 6721 and 6722 if a broker determines in good faith that an index is, or is not, a narrow-based index described in section 1256(g)(6) and reports in a manner consistent with that determination.
One commenter asked for an exemption from basis reporting for options on foreign currency and suggested that foreign currency be treated as a commodity. Because commodities and foreign currency are not specified securities, basis reporting by a broker for an option on foreign currency or an option on a commodity is not currently required under section 6045. Accordingly, no change is made in these final regulations in response to this comment.
A number of commenters asserted that neither the wash sale rules under section 1091 nor the short sale rules described in section 1233 should apply to a section 1256 option. One commenter asked for clarification about how holding period adjustments due to application of the wash sale provisions should be applied to section 1256 options. These comments have not been adopted because the changes requested are substantive in nature and outside the scope of the reporting rules.
Comments were also received on the rules in the proposed regulations relating to non-section 1256 options. Several commenters asserted that there are administrative issues involved in reporting over-the-counter (OTC) options and asked that OTC options be exempted from reporting. One commenter suggested that if exemptions were not granted, the IRS should create a “best efforts” safe harbor for OTC options. The Treasury Department and the IRS believe that it is reasonable to expect a broker to know the information required to report on an OTC option when it is entered into or when it is transferred into a customer's account. Moreover, the regulations under section 6045A require the transferor of an OTC option to provide detailed information to a receiving broker sufficient to describe the option. This could include data about the underlying asset, contract size, non-standardized strike price, and expiration date. These final regulations therefore apply to any OTC option on a specified security.
For a cash settled non-section 1256 option, the proposed regulations required a broker to adjust gross proceeds related to an option transaction by increasing gross proceeds by the amount of any payments received for issuing the option and decreasing gross proceeds by the amount of any payments made on the option. A number of commenters requested that, instead of decreasing gross proceeds by amounts paid out, brokers be permitted to report gross amounts paid and received with respect to the option. Under this approach, the gross proceeds box on Form 1099–B would include all payments received, and the basis box on Form 1099–B would reflect any payments made. These commenters noted that some broker systems already deal with equity options this way. This suggestion has not been adopted because it is not consistent with the overall concept of gross proceeds and basis reporting, which applies to all covered securities. The rules in these final regulations for a cash settled option are based upon the basic idea that costs related to the acquisition of a position affect basis, while the costs related to the sale or closeout of a position affect gross proceeds. This is consistent with the changes to the
Under these final regulations, expenses related to the sale of an asset must be deducted from gross proceeds and may not be added to basis. For a purchased option, the basis in the option will include the premium paid as well as any commissions, fees, or other transaction costs related to the purchase. Gross proceeds on the cash settlement of the purchased option should be adjusted to account for any commissions, fees, or other transaction costs related to the cash settlement. In the case of a written option, a broker must determine the amount of reportable proceeds by subtracting from the amount of the premium received for writing the option any settlement payments, commissions, or other costs related to the close out or cash settlement. At the suggestion of several commenters, a clarification has been added that the basis under this scenario should be reported as $0.
One commenter requested that for cash-settled options, acquisition costs be treated as adjustments to gross proceeds and that no adjustments be made to basis for acquisition costs. This comment has not been adopted because it is contrary to the requirements of § 1.263(a)-4(c), which require that acquisition costs be treated as part of basis.
One commenter requested that if multiple option contracts are bundled into a single investment vehicle and the components cannot be separately exercised, the investment will be treated as a single instrument with a single basis. These final regulations do not adopt this comment because the basis of each financial instrument is required to be accounted for separately.
Another commenter asked that the regulations explicitly address whether a broker must take into account the straddle rules under section 1092, including the qualified covered call rules in section 1092(c)(4). Consistent with the approach taken for broker basis reporting for stock, these final regulations explicitly provide that a broker will not take section 1092 into consideration when determining basis of an option that is a covered security.
Several comments were received asking for guidance in determining which options would be considered substantially identical for the purpose of applying the wash sale rules under section 1091. The 2010 final regulations only require a broker to apply the wash sale rules when the transaction involves covered securities with the same CUSIP number, and these final regulations do not change this rule.
The proposed regulations provided that a broker was permitted, but not required, to increase a customer's initial basis in stock for income recognized upon the exercise of a compensatory option or the vesting or exercise of other equity-based compensation arrangement. The preamble to the proposed regulations also stated that the IRS might add a field to Form 1099–B to indicate when stock was acquired via the exercise of a compensatory option. In response, commenters asked that there be no change to the Form 1099–B to reflect compensation status or, alternatively, that using the indicator be permitted, but not required. These commenters indicated that compensation information is not accessible to most brokers, and extensive reprogramming for both the underlying database and the reporting process would be required. The commenters also expressed concerns that, in many situations, a broker would have to accept customer-provided information in order to track the compensation-related status.
After consideration of the comments, the Treasury Department and the IRS agree a compensation-related field should not be added to the Form 1099–B. The lack of a mechanism to communicate whether the basis of stock has been adjusted for the exercise of a compensatory option coupled with a system involving discretionary broker adjustments for compensatory options would, however, be unworkable. Therefore, these final regulations provide that brokers are not permitted to adjust basis to account for the exercise of a compensatory option that is granted or acquired on or after January 1, 2014. This approach will eliminate confusion and uncertainty for an employee who has exercised a compensatory option. Under the permissive adjustment rule in the proposed regulations, without an indicator on Form 1099–B, an employee would not necessarily know whether the basis of the stock acquired through the exercise of a compensatory option had been adjusted by a broker to account for any income recognized by the employee due to the option exercise. By prohibiting adjustment by a broker, an employee will know that the basis number reported by the broker only reflects the strike price paid for the stock and that a basis adjustment may be necessary to reflect the full amount paid by the employee.
One commenter asked for guidance on how to implement backup withholding for option transactions. In particular, the commenter asked for clarification about whether a rule similar to § 31.3406(b)(3)–2(b)(4) applies, permitting a broker to withhold at either the time of sale or upon a closing transaction or lapse. The commenter also asked how to apply backup withholding to several situations involving physically settled options or when the taxpayer transfers an option or ends up closing out an option transaction at a loss. This comment is not adopted because backup withholding rules are outside the scope of these final regulations.
Several commenters requested that stock rights and warrants be excluded from basis reporting. Several other commenters addressed issues under sections 305 and 307. One commenter pointed out some administrative problems with the taxpayer election to allocate basis under section 307, including the fact that the election to allocate basis can be made after a broker's Form 1099–B reporting window closes. This commenter recommended requiring basis adjustments to reflect the issuance of stock rights or warrants only when section 307 requires allocation of basis because the value of the stock right or warrant represents 15% or more of the fair market value of the old stock. Another commenter noted that distributions of stock rights or warrants representing 15% or more of the value of the old stock are uncommon and recommended that brokers should not make an adjustment for the effects of section 307.
One commenter requested a clarification of the rules for a stock right or warrant that terminates other than by exercise or actual sale, so that a closing transaction that results in $0 proceeds is not a sale subject to reporting on a Form 1099–B. The commenter was concerned that in many cases a broker would have to report a lapse of a stock right or warrant by reporting $0 as proceeds on the Form 1099–B, even in situations where there is no basis to report.
After consideration of the comments, these final regulations provide that a broker is permitted, but not required, to apply the rules of sections 305 and 307 when reporting the basis of a stock right or warrant or any stock related to a stock right or warrant. This rule will permit the industry to deploy its resources
One commenter asked for an explicit exemption from reporting for single stock futures that fall under section 1234B or for guidance on how to apply section 1234B. This request was not adopted; instead, these final regulations add section 1234B contracts to the definitions of specified security and covered security. The Treasury Department and the IRS believe that there is no reason to exclude single stock futures on a specified security from information reporting when information reporting is generally required on stock, options on stock, and regulated futures contracts.
Numerous comments were received related to transfer reporting for debt instruments, as required by section 6045A. Many comments focused on the information that was to be included on the transfer statement. Some commenters argued for the transfer of original purchase information related to debt instruments because some brokers will recompute OID, market discount, bond premium, and acquisition premium through the transfer date and will use the recomputed numbers, instead of the numbers provided by the prior broker, to populate their data systems. Other commenters argued that only adjusted basis needs to be transferred to provide for subsequent accrual computations; these commenters point out that some adjustments, such as wash sale loss deferrals and holding period adjustments, will be reported accurately if adjusted basis is reported on a transfer statement, but may not be reflected if basis is recomputed based on original purchase information. Further, to the extent that a transferor broker might have used a computational method that is different from the method used by the receiving broker, as long as each broker is internally consistent in reporting income and adjusting basis, permitting the receiving broker to start from adjusted basis will help ensure that there is no duplication or omission of income and adjustments. Another commenter argued that the market discount, acquisition premium, and bond premium amounts should be implicit in the combination of adjusted issue price and adjusted cost basis, and transfer of the details is not needed. One commenter suggested treating each transfer as though it were a new purchase. This would entail comparing the reported adjusted basis to the adjusted issue price, determining new amounts of bond premium, market discount, or acquisition premium, and then basing all further accruals on these numbers.
After consideration of the comments, the Treasury Department and the IRS believe that brokers and customers are better served when all relevant information is provided when a security is transferred. These final regulations therefore generally require the information specified in the proposed regulations, and have expanded the list of information that must be provided to support the new requirement that a broker support customer debt instrument elections. It is not anticipated that a particular receiving broker will necessarily use all of the information received. For example, if a receiving broker's systems are set up to recompute debt instrument accruals from the issue date, that broker may not find the data for adjusted issue price as of the transfer date to be useful.
Several commenters also expressed concerns about transferring data purchased from third-party vendors. One commenter suggested that communicating the CUSIP identifier for a debt instrument might be sufficient to enable a receiving broker to retrieve information that applies to all debt instruments in a particular issue, such that some of the data described in the proposed regulations might not be necessary. Another commenter argued that data specific to a customer, such as initial purchase price and date, and the CUSIP should provide a receiving broker with all information needed to properly compute debt instrument accruals.
These final regulations, like the proposed regulations, require that a transferor broker provide all information necessary to allow a receiving broker to comply with its information reporting obligations. Consistent with the comments, if providing a CUSIP number or similar security identifier is adequate to enable the receiving broker to obtain some of the required information, a transferring broker is permitted to supply the CUSIP number or security identifier as a substitute for that information. For example, data that applies to all debt instruments in an issue, such as issuer name, issue date, coupon rate, coupon payment dates, or issue price, might be data that could be derived from a CUSIP or other security identifier. However, under these final regulations, like the proposed regulations, a receiving broker may request to receive the information specified in the regulations from the transferor broker. Further, data specific to a customer, such as price paid by the customer, the acquisition date, or yield, must be transmitted separately as these data will be different for each customer and cannot be derived from the CUSIP number.
A few commenters focused specifically on the list of debt instrument-specific data that was included in proposed § 1.6045A–1(b)(3). One commenter asked if the amount of acquisition premium already amortized should be added to the list, pointing out that accrued market discount and amortized bond premium are already reportable. One commenter asked that the date through which the transferor broker made adjustments be added to the list. These final regulations adopt these comments and add these data to the list of transfer statement items.
One commenter asked whether, when complying with the transfer statement rules under section 6045A for a section 1256 option, a broker may report the adjusted basis instead of the original basis for a position that has been marked to market. Section 1.6045A–1(b)(1)(vii) of the 2010 final regulations requires a broker to report the adjusted basis of a specified security. Therefore, no change is needed to address this comment.
One commenter asked for penalty relief for transfer reporting analogous to the relief that was provided for transfer reporting for stock in Notice 2010–67, 2010–43 I.R.B. 529. Under Notice 2010–67, although broker reporting for basis began for some stock acquired on or after January 1, 2011, transferring brokers were given penalty relief if they did not provide transfer statements for transfers occurring during 2011, and receiving brokers were instructed to treat a transfer during 2011 for which no transfer statement was received as the transfer of a noncovered security. Instead of penalty relief, the Treasury Department and the IRS believe that it is appropriate to provide additional time for brokers to phase in transfer reporting for transfers of debt instruments, options, and securities futures contracts, and the final regulations provide that transfer reporting for debt instruments, options, and securities futures contracts will be
A number of comments were received concerning returns relating to issuer actions affecting the basis of securities under section 6045B. Several commenters asked whether certain types of events would be reportable under section 6045B, including the issuance of a debt instrument, a reissuance of a debt instrument, and a reorganization in bankruptcy where new debt instruments are issued for old debt instruments. Section 6045B only applies to an issuer action that affects basis. The issuance of a debt instrument generally is not an issuer action affecting the basis of a debt instrument. Accordingly, in many cases, the issuance of a debt instrument is not subject to section 6045B. The legislative history, however, indicates that reorganizations, such as mergers and acquisitions, are among the organizational actions that can trigger reporting under section 6045B. Thus, for example, the issuance of a debt instrument in a recapitalization, including a recapitalization resulting from a significant modification or a bankruptcy reorganization, can be an issuer action affecting the basis of a debt instrument for purposes of section 6045B.
One commenter pointed out that a REMIC regular interest is excluded from being a covered security, but is not excluded from being a specified security. With respect to reporting under section 6045B, the commenter requested that if a specified security is not subject to basis reporting, issuer reporting under section 6045B should not be required. These final regulations clarify that a REMIC regular interest is not a specified security and, therefore, is not subject to reporting under section 6045B.
Section 1.6045B–1(a)(3) of the 2010 final regulations provides that an issuer may meet its reporting obligation under section 6045B by posting a copy of Form 8937 to its public Web site. One commenter renewed a request that the IRS permit an issuer to provide the information required by section 6045B on a Web site without posting a copy of Form 8937. The regulations do not adopt this suggestion because posting a copy of Form 8937 ensures consistent presentation of the reported information. Another commenter noted that posting a copy of Form 8937 could facilitate identity theft because the written signature of the certifying company official would be widely available. These final regulations allow an issuer to publicly post a Form 8937 with an electronic signature as an alternative to a written signature.
One commenter requested that a clearing organization involved in clearing exchange-traded options be treated as an issuer rather than a writer for purposes of section 6045B. Other commenters suggested language to clarify the identification of the party responsible for reporting in the case of an OTC option. In response to the commenters, these final regulations specify that a clearing organization that is the counterparty to an exchange-traded option is the issuer of the option for purposes of section 6045B, and the writer of an OTC option is the issuer for purposes of section 6045B.
One commenter pointed out that currently there is no safe harbor for modifications to non-debt instruments, so any modification of an option technically might result in a taxable event. The commenter recommended providing an assumption for brokers that changes to option terms do not result in a taxable event if section 1001 does not apply. This request is outside the scope of the current project and so no changes were made to these final regulations in response to this comment. It should be noted, however, that under these final regulations, an option issuer only needs to comply with § 1.6045B–1 if the change in the underlying asset results in a different number of option contracts. If the terms of the option are changed to reflect a corporate event, but the number of option contracts does not change, a section 6045B event has not occurred.
One commenter requested that foreign entities that are not U.S. payors and are either qualified intermediaries or participating foreign financial institutions be excluded from basis reporting requirements. The Treasury Department and the IRS intend to issue future guidance coordinating the reporting requirements applicable to qualified intermediaries and participating foreign financial institutions under chapter 61 (including section 6045) with the applicable chapter 4 reporting requirements.
As noted earlier in this preamble, a number of commenters requested that the rules for reporting interest income associated with a debt instrument acquired at a premium be conformed to the rules regarding basis reporting for these same debt instruments. Under the current information reporting rules under section 6049, interest income is reported without adjustment for bond premium or acquisition premium.
Under section 171(e) (which was added to the Code in 1988) and § 1.171–1 (which was amended in 1997 to reflect the addition of section 171(e)), amortized bond premium offsets stated interest payments. As a result, only the portion of a stated interest payment that is not offset by the amortized premium is treated as interest for federal income tax purposes. Under section 6049(a), the Secretary can prescribe regulations to implement the reporting of interest payments, which includes the determination of the amount of a payment that is reportable interest. Similarly, notwithstanding section 6049(d)(6)(A)(i), under section 6049(a), the Secretary can prescribe regulations to implement the reporting of OID, which includes the determination of the amount reportable as OID (interest).
The Treasury Department and the IRS believe that the income reporting and basis reporting rules should be consistent. Therefore, to improve consistency between income reporting and basis reporting and to provide immediate guidance to brokers and investors, this document adds temporary regulations under section 6049 to require broker reporting of interest (OID) income to reflect amounts of amortized bond premium or acquisition premium for a covered debt instrument.
Under the temporary regulations, for purposes of section 6049, a broker will assume that a customer has elected to amortize bond premium unless the broker has been notified that the customer has not made the election. It should be noted that this change applies only to the information reported by the broker to its customer. Thus, a customer that does not prefer to make the section 171 election can report interest on the customer's income tax return unadjusted for bond premium because the information reporting rules do not change the substantive rules affecting bond premium (or any of the other rules pertaining to OID, market discount, or acquisition premium). Moreover, a customer can notify a broker that the customer has not made or has revoked a section 171 election, and the broker is required to reflect this fact on the Form 1099–INT and the Form 1099–B. If a broker is required to report amounts reflecting amortization of bond premium, the temporary regulations allow a broker to report either a gross amount for both stated interest and amortized bond premium or a net amount of stated interest that reflects the offset of the stated interest payment
In addition, under the temporary regulations, for purposes of section 6049, a broker must report OID adjusted for acquisition premium in accordance with § 1.1272–2 by assuming that a customer has not elected to amortize acquisition premium based on a constant yield. However, if the broker has been notified that the customer has made an election to amortize acquisition premium based on a constant yield, the broker is required to reflect this fact on the Form 1099–OID and the Form 1099–B. The temporary regulations allow a broker to report either a gross amount for both OID and acquisition premium, or a net amount of OID that reflects the offset of the OID by the amount of amortized acquisition premium allocable to the OID.
Under § 1.1275–3(c) of the current final regulations, an issuer of a publicly offered debt instrument issued with OID must file a Form 8281, “Information Return for Publicly Offered Original Issue Discount Instruments,” within 30 days after the issue date of the debt instrument. The information from Form 8281 is used to develop the tables of OID information that are part of Publication 1212, “Guide to Original Issue Discount (OID) Instruments.” To be publicly offered, a debt instrument generally must be registered with the Securities and Exchange Commission as of the instrument's issue date. In many instances, a debt instrument issued in a private placement is registered with the Securities and Exchange Commission after the issue date. As a result, a Form 8281 is not required to be filed with the IRS and, therefore, the OID information generally does not appear in the Publication 1212 tables. A number of commenters on the proposed regulations asked that OID information on more debt instruments be provided in the tables to Publication 1212. In response to these comments, the regulations under § 1.1275–3(c) are amended to require the filing of a Form 8281 for a debt instrument that is part of an issue the offering of which is registered with the Securities and Exchange Commission after the issue date of the debt instrument. The Form 8281 is required to be filed within 30 days of the date the offering is registered with the Securities and Exchange Commission.
A number of commenters indicated that compliance with basis reporting requirements and the use of basis and other information reported by brokers will require considerable resources and effort on the part of return preparers and information recipients. The Treasury Department and the IRS are continuing to review all aspects of the information reporting process and are exploring ways to reduce the compliance burden for both brokers and for information recipients.
These regulations are effective when published in the
It has been determined that this rulemaking is not a significant regulatory action as defined in Executive Order 12866, as supplemented by Executive Order 13563. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations, and because the temporary regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply to the temporary regulations.
Pursuant to the Regulatory Flexibility Act (5 U.S.C. chapter 6), it is hereby certified that the final regulations in this document will not have a significant economic impact on a substantial number of small entities. Any effect on small entities by the rules in the final regulations flows directly from section 403 of the Act.
Section 403(a) of the Act modifies section 6045 to require that, when reporting the sale of a covered security, brokers report the adjusted basis of the security and whether any gain or loss with respect to the security is long-term or short-term. The Act also requires gross proceeds reporting for options. It is anticipated that these statutory requirements will fall only on financial services firms with annual receipts greater than $7 million and, therefore, on no small entities. Further, in implementing the statutory requirements, the final regulations generally limit reporting to information required under the Act.
Section 403(a) of the Act requires a broker to report the adjusted basis of a debt instrument that is a covered security. The holder of a debt instrument is permitted to make a number of elections that affect how basis is computed. To minimize the need for reconciliation between information reported by a broker to both a customer and the IRS and the amounts reported on the customer's tax return, the final regulations require a broker to take into account certain specified elections in reporting information to the customer. Therefore, under the final regulations, a customer must provide certain information concerning an election to the broker in a written notification, which includes a writing in electronic format. It is anticipated that this collection of information will not fall on a substantial number of small entities. Further, the final regulations generally implement the statutory requirements for reporting adjusted
Section 403(c) of the Act added section 6045A, which requires applicable persons to furnish a transfer statement in connection with the transfer of custody of a covered security. The modifications to § 1.6045A–1 effectuate the Act by giving the broker who receives the transfer statement the information necessary to determine and report adjusted basis and whether any gain or loss with respect to a debt instrument or option is long-term or short-term as required by section 6045 when the security is subsequently sold. Consequently, the final regulations do not add to the impact on small entities imposed by the statutory scheme. Instead, it limits the information to be reported to only those items necessary to effectuate the statutory scheme.
Section 403(d) of the Act added section 6045B, which requires issuer reporting by all issuers of specified securities regardless of size and even when the securities are not publicly offered. The modifications to § 1.6045B–1 limit reporting to the additional information for debt instruments and options necessary to meet the Act's requirements. Additionally, the final regulations, as modified, retain the rule that permits an issuer to report each action publicly instead of filing a return and furnishing each nominee or holder a statement about the action. The final regulations therefore do not add to the statutory impact on small entities but instead eases this impact to the extent the statute permits.
Therefore, because the final regulations in this document will not have a significant economic impact on a substantial number of small entities, a regulatory flexibility analysis is not required.
Pursuant to section 7805(f) of the Code, the proposed regulations preceding the final regulations in this document were submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business, and no comments were received. In addition, the proposed regulations accompanying the section 6049 temporary regulations in this document have been submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business.
The principal author of these regulations is Pamela Lew, Office of Associate Chief Counsel (Financial Institutions and Products). However, other personnel from the IRS and the Treasury Department participated in their development.
Income taxes, Reporting and recordkeeping requirements.
Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is amended as follows:
26 U.S.C. 7805 * * *
Section 1.6049–9T also issued under 26 U.S.C. 6049(a). * * *
(b) * * *
(c) * * *
(4) Subsequent registration.
(c) * * *
(4)
The additions and revisions read as follows:
(a) * * *
(3) * * *
(v) An interest in or right to purchase any of the foregoing in connection with the issuance thereof from the issuer or an agent of the issuer or from an underwriter that purchases any of the foregoing from the issuer;
(vi) An interest in a security described in paragraph (a)(3)(i) or (iv) of this section (but not including executory contracts that require delivery of such type of security);
(vii) An option described in paragraph (m)(2) of this section; or
(viii) A securities futures contract.
(8) The term
(9) The term
(14) The term
(i) Any share of stock (or any interest treated as stock, including, for example, an American Depositary Receipt) in an entity organized as, or treated for Federal tax purposes as, a corporation, either foreign or domestic (provided that, solely for purposes of this paragraph (a)(14)(i), a security classified as stock by the issuer is treated as stock, and if the issuer has not classified the security, the security is not treated as stock unless the broker knows that the security is reasonably classified as stock under general Federal tax principles);
(ii) Any debt instrument described in paragraph (a)(17) of this section, other than a debt instrument subject to section 1272(a)(6) (certain interests in or mortgages held by a REMIC, certain other debt instruments with payments subject to acceleration, and pools of debt instruments the yield on which may be affected by prepayments) or a short-term obligation described in section 1272(a)(2)(C);
(iii) Any option described in paragraph (m)(2) of this section; or
(iv) Any securities futures contract.
(15) * * *
(i) * * *
(A) A specified security described in paragraph (a)(14)(i) of this section acquired for cash in an account on or after January 1, 2011, except stock for which the average basis method is available under § 1.1012–1(e).
(C) A specified security described in paragraphs (a)(14)(ii) and (n)(2)(i) of this section (not including the debt instruments described in paragraph (n)(2)(ii) of this section) acquired for cash in an account on or after January 1, 2014.
(D) A specified security described in paragraphs (a)(14)(ii) and (n)(3) of this section acquired for cash in an account on or after January 1, 2016.
(E) An option described in paragraph (a)(14)(iii) of this section granted or acquired for cash in an account on or after January 1, 2014.
(F) A securities futures contract described in paragraph (a)(14)(iv) of this section entered into in an account on or after January 1, 2014.
(ii) * * * Acquiring a security in an account includes granting an option and entering into a short sale.
(17) For purposes of this section, the terms
(18) For purposes of this section, the term
(c) * * *
(3) * * *
(vii) * * *
(C) * * * The preceding sentence does not apply to a debt instrument issued on or after January 1, 2014. For a short-term obligation issued on or after January 1, 2014, see paragraph (c)(3)(xiii) of this section.
(D) * * * The preceding sentence does not apply to a debt instrument issued on or after January 1, 2014.
(x)
(xi) * * *
(C)
(xiii)
(4) * * *
(i) * * * N indicates on the transfer statement that the transferred stock was borrowed in accordance with § 1.6045A–1(b)(7).
(d) * * *
(2)
(ii)
(iii)
(3)
(5)
(6)
(ii)
(B)
(iii)
(iv)
(vii) * * *
R, an employee of C, a corporation, participates in C's stock option plan. On April 2, 2014, C grants R a nonstatutory option under the plan to buy 100 shares of stock. The option becomes substantially vested on April 2, 2015. On October 2, 2015, R exercises the option and purchases 100 shares. On December 2, 2015,
(7)
(8)
(m)
(2)
(A) An option on one or more specified securities (which includes an index substantially all the components of which are specified securities);
(B) An option on financial attributes of specified securities, such as interest rates or dividend yields; or
(C) A warrant or a stock right.
(ii)
(iii)
(3)
(4)
(i)
(ii)
(iii)
(iv)
(i) On January 15, 2014, C, an individual who is neither a dealer nor a trader in securities, writes a 2-year exchange-traded option on 100 shares of Company X through Broker D. C receives a premium for the option of $100 and pays no commission. In C's hands, the option produces capital gain or loss and Company X stock is a capital asset. On December 16, 2014, C pays $110 to close out the option.
(ii) D is required to report information about the closing transaction because the option is a covered security as described in paragraph (a)(15)(i)(E) of this section and was part of a closing transaction described in paragraph (a)(8) of this section. Under paragraph (m)(4)(ii) of this section, D must report as gross proceeds on C's Form 1099–B -$10 (the $100 received as option premium minus the $110 C paid to close out the option) and report $0 in the basis box on the Form 1099–B. Under section 1234(b)(1) and paragraph (d)(2) of this section, D must also report the loss on the closing transaction as a short-term capital loss.
(i) On January 15, 2014, E, an individual who is neither a dealer nor a trader in securities, buys a 2-year exchange-traded option on 100 shares of Company X through Broker F. E pays a premium of $100 for the option and pays no commission. In E's hands, both the option and Company X stock are capital assets. On December 16, 2014, E receives $110 to close out the option.
(ii) F is required to report information about the closing transaction because the option is a covered security as described in paragraph (a)(15)(i)(E) of this section and was part of a closing transaction described in paragraph (a)(8) of this section. Because the option is on the shares of a single company, it is an equity option described in section 1256(g)(6) and is not described in section 1256(b)(1)(C). Therefore, the rules of paragraph (m)(3) of this section do not apply, and F must report under paragraph (m)(4) of this section. Under paragraph (m)(4)(ii) of this section, F must report $110 as gross proceeds on the Form 1099–B for the gross proceeds E received and $100 in the basis box on the Form 1099–B to reflect the $100 option premium paid. Under section 1234(b)(1) and paragraph (d)(2) of this section, F must also report the gain on the closing transaction as a short-term capital gain.
(5)
(6)
(n)
(2)
(A) A debt instrument that provides for a single fixed payment schedule for which a yield and maturity can be determined for the instrument under § 1.1272–1(b);
(B) A debt instrument that provides for alternate payment schedules for which a yield and maturity can be determined for the instrument under § 1.1272–1(c); or
(C) A debt instrument for which the yield of the debt instrument can be determined under § 1.1272–1(d).
(ii)
(A) A debt instrument that provides for more than one rate of stated interest (including a debt instrument that provides for stepped interest rates);
(B) A convertible debt instrument described in § 1.1272–1(e);
(C) A stripped bond or stripped coupon subject to section 1286;
(D) A debt instrument that requires payment of either interest or principal in a currency other than the U.S. dollar;
(E) A debt instrument that, at one or more times in the future, entitles a holder to a tax credit;
(F) A debt instrument that provides for a payment-in-kind (PIK) feature (that is, under the terms of the debt instrument, a holder may receive one or more additional debt instruments of the issuer);
(G) A debt instrument issued by a non-U.S. issuer;
(H) A debt instrument for which the terms of the instrument are not reasonably available to the broker within 90 days of the date the debt instrument was acquired by the customer;
(I) A debt instrument that is issued as part of an investment unit described in § 1.1273–2(h); or
(J) A debt instrument evidenced by a physical certificate unless such certificate is held (whether directly or through a nominee, agent, or subsidiary) by a securities depository or by a clearing organization described in § 1.1471–1(b)(18).
(iii)
(iv)
(3)
(4)
(i)
(ii)
(iii)
(iv)
(v)
(5)
(ii)
(B)
(iii)
(6)
(i)
(ii)
(7)
(i)
(ii)
(B)
(iii)
(iv)
(v)
(8)
(9)
(10)
The additions and revisions read as follows:
(a) * * *
(1) * * *
(vi)
(b)
(v)
(vii)
(2)
(3)
(i) A description of the payment terms used by the broker to compute any basis adjustments under § 1.6045–1(n);
(ii) The issue price of the debt instrument;
(iii) The issue date of the debt instrument (if different from the original acquisition date of the debt instrument);
(iv) The adjusted issue price of the debt instrument as of the transfer date;
(v) The customer's initial basis in the debt instrument;
(vi) Any market discount that has accrued as of the transfer date (as determined under § 1.6045–1(n));
(vii) Any bond premium that has been amortized as of the transfer date (as determined under § 1.6045–1(n));
(viii) Any acquisition premium that has been amortized as of the transfer date (as determined under § 1.6045–1(n)); and
(ix) Whether the transferring broker has computed any of the information described in this paragraph (b)(3) by taking into account one or more elections described in § 1.6045–1(n), and, if so, which election or elections were taken into account by the transferring broker.
(4)
(i) The date of grant or acquisition of the option;
(ii) The amount of premium paid or received; and
(iii) Any other information required to fully describe the option, which may include a security identifier used by option exchanges, or details about the underlying asset, quantity covered, exercise type, strike price, and maturity date.
(5)
(6)
(8) * * *
(ii)
(9) * * *
(ii)
(iii)
* * * Under paragraph (b)(9)(i) of this section, S must provide a transfer statement to T that identifies the securities as gifted securities and indicates X's adjusted basis and original acquisition date. * * *
* * * Under paragraph (b)(9)(ii) of this section, T must provide a transfer statement to U that identifies the securities as gifted securities and indicates X's adjusted basis and original acquisition date of the stock. * * *
(10) * * * If the customer does not provide an adequate and timely identification for the transfer, a transferor must first report the transfer of any securities in the account for which the transferor does not know the acquisition or purchase date followed by the earliest securities purchased or acquired, whether covered securities or noncovered securities.
(12)
(ii)
(d)
(1) A transfer on or after January 1, 2011, of stock other than stock in a regulated investment company within the meaning of § 1.1012–1(e)(5);
(2) A transfer on or after January 1, 2012, of stock in a regulated investment company;
(3) A transfer on or after January 1, 2015, of an option described in § 1.6045–1(a)(14)(iii), a securities futures contract described in § 1.6045–1(a)(14)(iv), or a debt instrument described in § 1.6045–1(a)(15)(i)(C); and
(4) A transfer on or after January 1, 2017, of a debt instrument described in § 1.6045–1(a)(15)(i)(D).
The additions and revisions read as follows:
(a) * * *
(3)
(h)
(i) If the option is an exchange-traded option, any clearinghouse or clearing facility that serves as a counterparty is treated as the issuer of the option for purposes of section 6045B.
(ii) If the option is not an exchange-traded option, the option writer is treated as the issuer of the option for purposes of section 6045B.
(2)
On January 15, 2014, F, an individual, purchases a one-year exchange-traded call option on 100 shares of Company X stock, with a strike price of $110. The call option is cleared through Clearinghouse G. Company X executes a 2-for-1 stock split as of April 1, 2014. Due to the stock split, the terms of F's option are altered, resulting in two option contracts, each on 100 shares of Company X stock with a strike price of $55. All other terms remain the same. Under paragraph (h)(1)(i) of this section, Clearinghouse G is required to prepare an issuer report for F.
On January 31, 2014, J, an individual, purchases from K a non-exchange traded 7-month call option on 100 shares of Company X stock, with a strike price of $110. Company X executes a 2-for-1 stock split as of April 1, 2014. Due to the stock split, the terms of J's option are altered, resulting in one option contract on 200 shares of Company X stock with a strike price of $55. All other terms of the option remain the same. Under paragraph (h)(1) of this section, because the number of option contracts did not change, K is not required to prepare an issuer report for J.
(i) [Reserved]
(j)
(1) Organizational actions occurring on or after January 1, 2011, that affect the basis of specified securities within the meaning of § 1.6045–1(a)(14)(i) other than stock in a regulated investment company within the meaning of § 1.1012–1(e)(5);
(2) Organizational actions occurring on or after January 1, 2012, that affect the basis of stock in a regulated investment company;
(3) Organizational actions occurring on or after January 1, 2014, that affect the basis of debt instruments described in § 1.6045–1(n)(2)(i) (not including the debt instruments described in § 1.6045–1(n)(2)(ii));
(4) Organizational actions occurring on or after January 1, 2016, that affect the basis of debt instruments described in § 1.6045–1(n)(3);
(5) Organizational actions occurring on or after January 1, 2014, that affect the basis of options described in § 1.6045–1(a)(14)(iii); and
(6) Organizational actions occurring on or after January 1, 2014, that affect the basis of securities futures contracts described in § 1.6045–1(a)(14)(iv).
(a)
(b)
(c)
(d)
26 U.S.C. 7805.
(b) * * *
In Title 30 of the Code of Federal Regulations, Parts 1 to 199, revised as of July 1, 2012, on page 246, in § 48.6, paragraph (b)(10) is corrected to read as follows:
(b) * * *
(10)
In Title 30 of the Code of Federal Regulations, Parts 1 to 199, revised as of July 1, 2012, on page 241, in § 48.3, paragraph (a) introductory text is corrected to read as follows:
(a) Except as provided in paragraphs (o) and (p) of this section, each operator of an underground mine shall have an MSHA approved plan containing programs for training new miners, training experienced miners, training miners for new tasks, annual refresher training, and hazard training for miners as follows:
Coast Guard, DHS.
Notice of deviation from drawbridge regulation.
The Coast Guard is issuing a temporary deviation from the regulation governing the operation of the Southport SR27 Bridge across Townsend Gut, mile 0.7, between Boothbay Harbor and Southport, Maine. The bridge owner, Maine Department of Transportation, will be performing structural repairs at the bridge. This deviation allows the bridge to operate on a temporary schedule for eight weeks to facilitate scheduled bridge maintenance.
This deviation is effective from April 27, 2013 through June 28, 2013.
Documents mentioned in this preamble as being available in the docket are part of docket USCG–2013–0223 and are available online at
If you have questions on this deviation, call or email Mr. John McDonald, Project Officer, First Coast Guard District, telephone (617) 223–8364,
The Southport SR27 Bridge, across Townsend Gut, mile 0.7, between Boothbay Harbor and Southport, Maine,
The waterway is transited by recreational and commercial fishing boats. There is an alternate route for navigation around Southport.
The bridge owner, Maine Department of Transportation, requested a temporary deviation from the normal operating schedule to facilitate deck repairs at the bridge.
Under this temporary deviation, the Southport SR27 Bridge shall operate as follows: From April 27, 2013, through May 27, 2013, between 6 a.m. and 6 p.m., Monday through Friday, except holidays, the draw shall open on signal, every two hours, at 6 a.m., 8 a.m., 10 a.m., 12 p.m., 2 p.m., 4 p.m., and 6 p.m.
From May 28, 2013, through June 28, 2013, between 6 p.m. and 6 a.m., Monday through Friday, except holidays, the draw shall open on signal at 6 p.m., 8 p.m., 10 p.m., 2 a.m., and 6 a.m.
In accordance with 33 CFR 117.35(e), the bridge must return to its regular operating schedule immediately at the end of the designated time period. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Coast Guard, DHS.
Temporary Final rule.
The Coast Guard is establishing a temporary safety zone within the Lake Moovalya region of the navigable waters of the Colorado River in Parker, Arizona for the Blue Water Resort & Casino West Coast Nationals. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, and participating vessels. Persons and vessels are prohibited from entering into, transiting through, or anchoring within this safety zone unless authorized by the Captain of the Port or his designated representative.
This rule is effective from 6 a.m. on April 20, 2013, until 6 p.m. on April 21, 2013. It will be enforced from 6 a.m. to 6 p.m. daily on April 20 and 21, 2013.
Documents mentioned in this preamble are part of docket USCG–2013–0095. To view documents mentioned in this preamble as being available in the docket, go to
If you have questions on this rule, call or email Petty Officer Bryan Gollogly, Waterways Management, U.S. Coast Guard Sector San Diego; Coast Guard; telephone 619–278–7656, email
The Coast Guard is issuing this final rule without prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issue a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing a notice of proposed rulemaking (NPRM) with respect to this rule because delay would be impracticable. The Coast Guard did not receive necessary information from the event sponsor in time to publish a notice of proposed rulemaking. The event is scheduled to take place, and as such, immediate action is necessary to ensure the safety of vessels, spectators, participants, and others in the vicinity of the marine event on the dates and times this rule will be in effect.
Under 5 U.S.C. 553(d)(3), for the same reasons mentioned above, the Coast Guard finds that good cause exists for making this rule effective less than 30 days after publication in the
The legal basis for this temporary rule is the Ports and Waterways Safety Act, which authorizes the Coast Guard to establish safety zones (33 U.S.C. sections 1221
RPM Racing Enterprises is sponsoring the Blue Water Resort & Casino West Coast Nationals, which is held in Parker, Arizona. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, sponsor vessels, and other vessels and users of the waterway. This event involves powerboats racing along a closed course. The size of the boats varies from eight to sixteen feet in length. Approximately 100 boats will be participating in this event. The sponsor will provide two patrol and two rescue boats to help facilitate the event and ensure public safety.
The Coast Guard is establishing a safety zone that will be enforced from 6 a.m. to 6 p.m. on April 20, 2013, and April 21, 2013. This safety zone is necessary to provide for the safety of the crews, spectators, participants, and other vessels and users of the waterway. Persons and vessels will be prohibited from entering into, transiting through, or anchoring with this safety zone unless authorized by the Captain of the Port, or his designated representative. This temporary safety zone includes the waters of the Colorado River between Headgate Dam and 0.5 miles north of the Blue Water Marina in Parker, Arizona. Before the effective period, the Coast Guard will publish a Local Notice to Mariners (LNM).
We developed this rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on these statutes and executive orders.
This rule is not a significant regulatory action under section 3(f) of
We expect the economic impact of this rule to be so minimal that a full Regulatory Evaluation is unnecessary. This determination is based on the size, timeframe, and location of the safety zone. Commercial vessels will not be hindered by the safety zone. Recreational vessels may transit through the established safety zone during the specified times if they obtain authorization from the Captain of the Port or his designated representative.
The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601–612, as amended, requires federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.
This rule will affect the following entities, some of which might be small entities: the owners or operators of vessels intending to transit or anchor in the impacted portion of the Colorado River from 6 a.m. to 6 p.m. on April 20, 2013, and April 21, 2013.
This safety zone will not have a significant economic impact on a substantial number of small entities for the following reasons. This safety zone will only be enforced for two twelve-hour periods. Although the safety zone will apply to the entire width of the river, traffic will be allowed to pass through the zone with the permission of the Coast Guard Captain of the Port or his designated representative. Before the effective period, the Coast Guard will publish a Local Notice to Mariners (LNM).
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104–121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1–888–REG–FAIR (1–888–734–3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this rule under that Order and have determined that it does not have implications for federalism.
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This rule will not affect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and does not create an environmental risk to health or risk to safety that may disproportionately affect children.
This rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
This action is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this rule under Department of Homeland Security Management Directive 023–01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321–4370f), and have determined that this action is one of a category of actions which do not individually or cumulatively have a significant effect on the human environment. This rule involves the establishment of a safety zone. This rule is categorically excluded, under figure 2–1, paragraph (34)(g), of the Instruction.
An environmental analysis checklist and a categorical exclusion determination are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; 33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5; Pub. L. 107–295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(c)
(d)
(2) Mariners requesting permission to transit through the safety zone may request authorization to do so from the Patrol Commander. The Patrol Commander may be contacted on VHF–FM Channel 16.
(3) All persons and vessels shall comply with the instructions of the Coast Guard Captain of the Port or his designated representative.
(4) Upon being hailed by U.S. Coast Guard patrol personnel by siren, radio, a flashing light, or other means, the operator of a vessel shall proceed as directed.
(5) The Coast Guard may be assisted by other federal, state, or local agencies.
Postal Service
Final rule.
The Postal Service is revising
On October 17, 2012, the Postal Service published a Notice of Proposed Rulemaking in the
For questions regarding full-service requirements, contact the Postal Service by email at
In January 2009, the Postal Service offered the mailing industry two Intelligent Mail options for automation discounts, which consisted of basic-service and full-service. Currently, a large number of mailers are using these two options and reaping numerous benefits and value.
Since the introduction of full-service Intelligent Mail, the Postal Service has worked closely with mailers, software vendors, and mail service providers to simplify, refine, and evolve full-service offerings. While thousands of users demonstrated the ability to meet the requirements for full-service Intelligent Mail, the Postal Service recognizes that this initiative requires significant changes for those mailers who currently benefit from automation discounts but are not presenting full-service mailings. Therefore, the Postal Service is continually working with the mailing industry to simplify the transition to full-service Intelligent Mail.
Full-service Intelligent Mail combines the use of unique barcodes with the provision of electronic information regarding the makeup and preparation of mail, which provides high-value services and enables efficient mail processing.
Mailings must bear Intelligent Mail barcodes on mailpieces, trays, and containers, where applicable. Also, mailers must submit mailing documentation electronically.
When preparing full-service mailings, mailers are required to:
• Apply unique Intelligent Mail barcodes (IMb) to identify each postcard, letter, and flat mailpiece.
• Individually meet the eligibility requirements for automation prices according to class and shape.
• Apply unique Intelligent Mail tray barcodes (IMtb) on trays, tubs, and sacks.
• Apply unique Intelligent Mail container barcodes (IMcb) on placards for containers, such as pallets, when required.
• Schedule appointments through the Facility Access and Shipment Tracking system (FAST ®) if mail is accepted at an origin facility and entered at a downstream USPS
• Use an approved electronic method to transmit mailing documentation and postage statements to the Postal Service.
• If the mailing is prepared or presented on behalf of another entity, the electronic documentation (eDoc) must include additional information to support the by/for mailing relationships. Mail service providers (agents) do not have to provide by/for data for mail owners with 5,000 or fewer pieces in a mailing. All other mailings must include by/for information. The mail owner and mailing agent are described as follows:
The strategic vision of the Postal Service is to create 100 percent visibility for mail in the mail stream. This visibility provides full-service mailers with near real-time data that specifies the location of mailpieces within the postal mail stream and the delivery day.
The Postal Service continues the ongoing transformation of data visibility and evolution of technological innovations to achieve this vision.
The mailer's use of full-service Intelligent Mail is an integral part of the Postal Service's ongoing strategy to provide cost-effective and service-responsive mailing services. Efficient use of postal resources can be achieved with advance information about the content and makeup of the mail. As mail is processed and sorted, postal sorting equipment captures volume and destination information. The Postal Service built and is refining systems that make information available to downstream postal facilities for use with operational planning. The planning data enabled through full-service mailings provides significant opportunities for improvements in efficiency and service performance.
If all guidelines are followed and requirements met, full-service Intelligent Mail offers advantages to mailers and the Postal Service.
• Mailers receive free undeliverable-as-addressed information including address correction service (ACS) and nixie service. (A nixie is a mailpiece that cannot be sorted or delivered because of an incorrect, illegible, or insufficient delivery address. Nixie service enables the processing of mail that cannot be forwarded or delivered as addressed and notifies mailers electronically of the specific reason for non-delivery.)
• A mailer receives start-the-clock information indicating when the mail was accepted by the Postal Service.
• Mailers receive container, tray, bundle, and mailpiece scans from induction to destination processing.
• Mailers are able to more effectively plan operations, assess the success of advertising campaigns, and improve customer interaction.
• Mailers are provided with comprehensive information on the status of mailings as they progress through the postal mail stream.
• Visibility enables mailers to respond more effectively to customer inquiries on the status of bills, statements, catalogs, and publications.
• A mailer's annual mailing permit fee is waived when the mailer enters 90 percent or more of full-service volume using the associated permit within the year.
• The “Mail Anywhere” program allows the use of a single permit at any
• Simplified mail entry and acceptance through programs enabled by full-service including eInduction and Seamless Acceptance.
• Visibility into the flow of mail through the postal mail stream enables enhanced diagnostics of service performance. The ability to measure service performance is available for each full-service mailing.
• Scan data allows the Postal Service to measure the number of hours and minutes between operations.
• Scan data allows the Postal Service to identify operational bottlenecks and continue to improve service for commercial First-Class Mail, Standard Mail, Periodicals, and BPM.
• Ability to provide real-time alerts to postal operations enables employees to respond to and avoid potential service failures.
• Advance notification of volume and makeup of commercial mail enables improved resource planning.
• Ability to accurately track mail volumes as they move through the postal network enables improved management and staffing of operations.
• Simplified mail acceptance processes increase productivity. With the availability of full-service mailing data and unique identifiers, the business mail acceptance procedures are streamlined with programs such as eInduction and Seamless Acceptance.
After January 26, 2014, acceptance employees will continue to perform existing verification and assessment processes. Existing verifications include
In addition to the existing verifications described above, acceptance employees perform additional verifications on full-service mailings to ensure that Intelligent Mail barcodes are present and readable on mailpieces, trays, and containers where applicable and that the mailing is presented with proper eDoc. The existing thresholds used to verify and qualify full-service mailings for readable barcodes and submission of eDoc will apply. Should a mailing fail existing verifications, the mailer may choose to have the disqualified mailing returned for re-work or pay the additional postage to mail at a non-automation price.
In addition to the above verification processes, the Postal Service performs additional validations of the following information contained in the eDoc submitted with full-service mailings. The Postal Service provides detailed data from these verifications including by/for information, service type ID, mailer ID, unique barcodes (piece, handling unit, container), entry facility, and co-palletization information.
• Service Type ID: A service type ID that is provided in the IMb and contained in the eDoc is appropriate for the class of mail and service level of the mailpiece.
• Mailer ID: A mailer ID that is provided in the IMb, IMtb, and/or IMcb and contained in the eDoc is valid (registered with the USPS Mailer ID system).
• Unique Piece Barcode: An IMb contained in the eDoc is unique across mailings for 45 days. Exception: Small mailings that have fewer than 10,000 pieces, where postage is affixed to each piece at the correct price or each piece is of identical weight and the mailpieces are separated by price, can use the same serial number for all pieces in the mailing. In this case, uniqueness is required for the serial number at the mailing level. A different serial number should be used for each mailing and the serial number cannot be repeated within 45 days.
• Unique Tray Barcode: An IMtb that contained in the eDoc is unique across mailings for 45 days. Exception: Small mailings that have fewer than 10,000 pieces can use the same serial number for all trays in the mailing, if postage is affixed to each piece at the correct price, or the pieces are of identical weight and separated by price.
• Unique Container Barcode: An IMcb contained in the eDoc is unique across mailings for 45 days.
• Co-Palletization: Co-palletized mailings must have eDoc submitted by both the origin facility and the consolidator to describe the movement of trays and sacks.
• Entry Facility: Entry facility provided in eDoc (Locale key or ZIP Code) is a valid USPS facility.
• By/For: Electronic documentation is checked to ensure that the mail owner and mailing agent identification are accurately populated.
The results of additional full-service electronic verifications are displayed in reports aggregated over a one-month period. The Postal Service continues to work with the mailing industry to share the results of these reports and address issues and gaps. No assessments will be made as a result of any additional full-service electronic verification until July 1, 2014. To develop reasonable thresholds and measure electronic documentation quality, the Postal Service will evaluate the data trends of full-service electronic verifications.
The Postal Service received comments from 52 respondents within the mailing industry. These comments, in addition to feedback from the Mailers Technical Advisory Council (MTAC), Postal Customer Councils (PCC), and other outreach efforts, allowed the Postal Service to develop initiatives that can enable mailers to efficiently transition to full-service Intelligent Mail.
The Postal Service appreciates all of the valuable comments that were provided. The following concerns were expressed:
How will the Postal Service verify the 90 percent requirement to obtain the permit fee waiver? If the percentage drops below 90, is the client be assessed a charge?
The Postal Service verifies that every individual mailing meets the 90 percent full-service criteria by checking the full-service percentage on the postage statements as they are processed. If every statement meets the 90 percent full-service criteria, the permit fee will not be activated and required when it is due. If, however, a mailing fails to meet the 90 percent full-service threshold, the annual permit fee is required and activated on the date of the failure to process the mailing. The annual fee will be good for one year.
In response to industry feedback, the Postal Service reviewed an alternative approach to consider waiving the annual permit fee when the cumulative volume throughout the year remains at or over 90 percent full-service.
When a mailing fails to qualify for full-service Intelligent Mail, the penalties assessed are substantial. It is imperative that the Postal Service be as precise as possible about qualification and verification requirements.
Please clarify what is measured to validate that the full-service requirements are being met. Is there a threshold or tolerance of less than 100 percent of the pieces in a full-service mailing, yet that mailing still qualifies for automation prices?
After January 26, 2014, acceptance employees will continue to perform existing verification and assessment processes. Existing verifications include validation of the mailpiece dimensions, shape, weight, flexibility, barcode quality, content, presort makeup, and automation eligibility. Should a mailing fail existing verifications, the mailer may choose to have the disqualified mailing returned for re-work or pay the additional postage. The existing thresholds used to verify and qualify automation mailings will apply.
In addition to the existing verifications described above, acceptance employees perform additional verifications on full-service mailings to ensure that Intelligent Mail barcodes are present, readable, and accurate on mailpieces, trays and containers where applicable, and that the mailing is presented with electronic documentation. The existing thresholds used to verify and qualify full-service mailings will apply.
Should a mailing fail the existing verifications, the mailer may choose to have the disqualified mailing returned for re-work or pay the additional postage to mail at a non-automation price.
Additionally, the Postal Service performs validations of the information
No assessments will be made as a result of any full-service electronic verification until July 1, 2014. To develop reasonable thresholds and measure electronic documentation quality, the Postal Service evaluates the data trends of full-service electronic verifications.
Our organization is concerned about the revision to DMM 705.24.1, “Full-service automation mailings may include automation-compatible pieces without barcodes, with POSTNET barcodes, or with Intelligent Mail barcodes. Mailings of full-service automation letters must not be comingled in the same tray with automation-compatible pieces without barcodes, with POSTNET barcodes,
This revision seems to overlook the realities of mail production operations. It is simply not possible to validate and ensure that every single mailpiece is 100 percent full-service. However, when operations are finalized, all pieces can be fully validated and identified in the eDoc within an appropriate tolerance.
Based on customer feedback, this language has been revised in the
Not all mailings eligible for automation prices are currently supported electronically by
The Postal Service is working with the mailing industry to resolve the current technical issues preventing the upload of eDoc for all full-service automation mailings prior to January 26, 2014.
Due to technical limitations of the current Mail.dat and
The Postal Service is working with the mailing industry to resolve the current technical issues for MLOCR bundled-based flats prior to January 26, 2014.
How will the Postal Service focus more attention and resources on resolving issues regarding systems and processes around CRID/MID assignment and maintenance? Also, how does the Postal Service plan to improve the customer-facing processes and systems, especially as it relates to CRID/MID assignments and the BCG?
There are currently three methods whereby mail service providers and mail owners can acquire 9-Digit MIDs and/or CRIDs. These methods were described in the “Quick Step Guide to Nine-Digit MID and/or CRID Acquisition”, posted on RIBBS at
Manual requests for MIDs and CRIDs will be handled by the Postal Service Help Desk, which allows mailers to request a ticket number and track the time to resolve issues.
In July 2013, the Postal Service will implement functionality for a fourth method that allows mail service providers to obtain CRIDs and MIDs on behalf of customers, through the Business Customer Gateway (BCG) interface. Additionally, there will be enhancements to allow users to more easily manage their profile when adding or removing business locations and services.
Our customers view the mail service provider's requests for MIDs/CRIDs as harassment rather than help. In fact, they have us log into the BCG on their behalf to obtain a MID/CRID for mailing, because they have no interest in setting this up themselves.
The Postal Service established some simpler ways for mail service providers to obtain MIDs/CRIDs, but unfortunately the methods established were not yet responsive enough to meet the needs of our customers, which force us to continue the tedious process of creating them individually. Often, we don't have 24 hours to wait for MIDs/CRIDs.
There are currently three methods through which mail service providers and mail owners can acquire 9-Digit MIDs and/or CRIDs. These methods were described in detail in the “Quick Step Guide to Nine-Digit MID and/or CRID Acquisition”, posted on RIBBS at
In July 2013, the Postal Service will implement functionality for a fourth method that allows mail service providers to obtain CRIDs and MIDs on behalf of their customers through the BCG interface. In addition, there are enhancements to allow users to more easily manage their profile, when adding or removing business locations and services.
There are issues with the MIDs that are required on the mailpieces, trays, and pallets. Presently, the Postal Service doesn't verify that the MIDs used in mailings are correct and authorized by the MID owner for use in a particular mailing, which could potentially lead to data going to the wrong organization.
It is the responsibility of the mail owner or mail service provider to ensure that information provided is accurate and complete. To help support mail owners and mail service providers, the
Further information on MIDs and CRIDs can be found in the “Quick Step Guide to Nine-Digit MID and/or CRID Acquisition”, posted on RIBBS at
How much time will mailers be given to take corrective action on mail quality errors, and what are the penalties for non-compliance?
After January 26, 2014, acceptance employees will continue to perform additional verifications on full-service mailings to ensure that Intelligent Mail barcodes are present and readable on mailpieces, trays, and containers where applicable, and that the mailing is presented with proper eDoc. The existing thresholds used to verify and qualify full-service mailings to ensure that barcodes are present and readable and submission of eDoc will apply. Should a mailing fail existing verifications, the mailer may choose to have the disqualified mailing returned for re-work or pay the additional postage to mail at a non-automation price.
In addition to the full-service verifications described above on the physical mail, the USPS performs validations of information contained in the electronic documentation submitted with full-service mailings. The results of these full-service electronic verifications are displayed in reports aggregated over a one-month period. The USPS evaluates the data trends of full-service electronic verifications to develop reasonable thresholds to measure electronic documentation quality. Results from electronic verifications should be displayed to the mailer within 48 hours of the postage statement finalization. Mailers may use the Mailer Scorecard report in the
No assessments will be made as a result of any full-service electronic verification until July 1, 2014. Information on accessing and using the Mailer Scorecard can be found on RIBBS at
Please provide clarity regarding how the Postal Service plans to manage quality errors — namely: What evidence will be provided to the mailer? Are mailers allowed to fix errors? Also, if mail is disqualified from using full-service Intelligent Mail, how can it re-qualify? What is the timeframe in which the Postal Service will communicate quality errors to the mailer and mail service provider?
After January 26, 2014, acceptance employees will continue to perform additional verifications on full-service mailings to ensure that Intelligent Mail barcodes are present, and readable on mailpieces, trays, and containers where applicable, and that the mailing is presented with proper eDoc. The existing thresholds used to verify and qualify full-service mailings to ensure that barcodes are present and readable and submission of eDoc will apply. Should a mailing fail existing verifications, the mailer may choose to have the disqualified mailing returned for re-work or pay the additional postage to mail at a non-automation price.
In addition to the full-service verifications described above on the physical mail, the USPS performs validations of the information contained in the electronic documentation submitted with full-service mailings. The results of these full-service electronic verifications are displayed in reports aggregated over a one-month period. The USPS evaluates the data trends of full-service electronic verifications to develop reasonable thresholds to measure electronic documentation quality. Results from electronic verifications should be displayed to the mailer within 48 hours of the postage statement finalization.
Mailers may use the Mailer Scorecard report in the
No assessments will be made as a result of any full-service electronic verification until July 1, 2014. Information on accessing and using the Mailer Scorecard can be found on RIBBS:
How will the Postal Service continue to improve systems and processes around full-service testing?
The USPS worked with the mailing industry to identify full-service gaps, and is working to implement corrections and enhancements. We implemented changes to improve system throughput, capacity, and performance. We have also enhanced our testing environment to support more production-like volume for testing and performance.
The Postal Service developed a process to authorize software vendors for electronic documentation and full-service capabilities. Use of authorized software simplifies the onboarding process for mailers. The Postal Service published the list of authorized software vendors on RIBBS at
Mailers using authorized software are asked to submit a single file to TEM to show they can use their software to generate accurate eDoc. Mailers can view the postage statements and supporting documentation to ensure the accuracy of the transaction in the TEM environment. Once a mailer has submitted and reviewed the single file, the testing process is complete.
Documentation regarding the simplified TEM process can be found on RIBBS at
By not offering a fully automated TEM, the Postal Service unnecessarily relies on processes that are not extensible. Mailers will likely delay full-service implementation until the end of 2013, which creates a bottleneck. The current TEM is not set up to handle a massive influx of mailers — what are your plans to address this matter?
Since October 2012, the Postal Service published a list of software products authorized for eDoc and full-service mailing scenarios. The TEM onboarding process has been simplified for mailers using an authorized software product. Mailers submit a single file to TEM that shows they are able to use the software and generate accurate eDoc. Mailers can view the postage statement and supporting documentation to ensure accuracy of the transaction in the TEM environment. Once a mailer has submitted and reviewed the single file, the testing process is complete. Further
In addition to TEM, the Postal Service is establishing a pre-production environment available for mailers to use for testing. This environment is available at the start of testing for an upcoming release.
Please clarify the following information regarding eDoc (Is this a new or existing requirement?): “When entering full-service mailings, eDoc is required. A mailer's eDoc identifies the unique IMb applied to each mailpiece, tray, tub, sack, and container; it describes how mailpieces are linked to handling units, such as trays, tubs, and sacks; and identifies how mailpieces and handling units are linked to containers. Additionally, eDoc identifies spoilage or shortage of pieces in a mailing, the preparer of the mailing, and the mailer for whom the mailing is prepared (i.e., mail owner). Mail owner identification is required for all pieces in a full-service mailing.”
The use of detailed eDoc, including nesting and by/for information, is an existing requirement for full-service. The Postal Service allows the use of logical containers and trays to simplify the requirements to track each mailpiece to a handling unit and each handling unit to a container. Logical containers/trays allow all mail going to the same destination at the same presort level to be handled as a single logical entity. Individual mailpieces can be traced to a destination instead of a physical tray. Additional technical details on the requirements to complete eDoc for full-service can be found on RIBBS in the “Guide to Intelligent Mail for Letters and Flats.”
We recommend that the Postal Service provide a matrix of mailing types that must comply with the eDoc standards and those which are not required to comply. Also, it is recommended that the matrix identify the requirements in which the non-supported mailings must comply to ensure automation prices. If the Postal Service plans to transition those mailing types to eDoc capabilities, then a schedule should be provided.
The Postal Service plans to support all full-service automation eligible mailings with eDoc before January 26, 2014. The following classes and mail types are covered by full-service: First-Class Mail cards, letters, and flats; Standard Mail letters and flats except for Saturation ECR flats; Periodicals letters and flats; and nonpresorted and presorted Bound Printed Matter (BPM) flats (except BPM flats entered at destination delivery units “DDUs”). Full-service is an option but will not be required for Standard Mail enhanced carrier route (ECR) basic, high-density, and high-density plus flats.
Under appointment scheduling, please explain “linking” container data. Is this a different process from “providing” container data?
“Linking” container data refers to associating a container to a specific FAST appointment to notify the Postal Service that a container will arrive at a facility on a specific date or by a designated time.
Our organization is concerned about the revision to DMM 705.24.4.4, “Unless otherwise authorized, documentation must describe how each mailpiece is linked to a uniquely identified tray or sack and how each mailpiece and tray or sack is linked to a uniquely identified container. Linking to logical trays, sacks, and containers via sibling records is an option when linking to a specific tray, sack, or container is not feasible.” Clarification to the term “authorized” or at least identification of the authorization scenario is requested. For example, authorization may be warranted because of file submission methods, special agreements, or as defined in a section of the DMM or a specific guide. Similarly, clarification is necessary regarding the process to determine “feasibility” when allowed to use the “logical” or physical option. Is it a mailer or USPS decision?
Previously, the use of logical handling units and containers was limited to MLOCR mailers. Based on feedback from the mailing industry, the Postal Service will now make the logical option available to all mailers in all mailing environments. The decision to present mail in physical or logical containers is a mailer's decision.
The Postal Service continues to develop enhancements, simplify existing tools, streamline the processes for mailers to prepare mailings, and provide ease of use for all mailers to transition to full-service Intelligent Mail. The Postal Service also recognizes there are costs for mailers associated with converting to full-service Intelligent Mail.
In support of the transition to full-service Intelligent Mail, the Postal Service offers the following incentives, on-boarding simplifications, process enhancements, and self-service tools:
A mailer's qualifying volume includes:
First-Class Mail automation cards, letters, and flats.
Standard Mail automation letters and flats, which includes:
Periodicals automation letters and flats and carrier-route letters and flats.
BPM barcoded flats: presorted non-DDU, presorted DDU, and carrier route.
125,001–500,000 qualifying pieces = $2,000 postage credit.
500,001–2,000,000 qualifying pieces = $3,000 postage credit.
More than 2,000,000 qualifying pieces = $5,000 postage credit.
The Tech Credit redemption period runs from June 1, 2013, through May 31, 2014. A qualified business location may redeem its Tech Credit amount as a postage credit when:
The permit holder's paying permit is linked to a qualified business location.
The postage statement bears 90 percent or more full-service pieces.
The postage statement submission type is Mail.dat or Mail.XML.
Upon submission of an eligible postage statement, the Tech Credit will
Detailed information regarding the Tech Credit program is available on RIBBS at
Mailers using certified software are asked to submit only a single file to TEM to show they can use the software to generate accurate eDoc. Mailers can view the postage statements and supporting documentation to ensure the accuracy of each transaction in the TEM environment. Once the mailer has submitted and reviewed the single file, the testing process is complete. Documentation regarding the simplified TEM process can be found on RIBBS at
Other enhancements to the systems include the following:
Full-service Intelligent Mail may consist of mailpiece barcodes, tray barcodes, and container barcodes as follows:
•
•
•
When automation mailings are not required to be containerized (not enough mail to require a pallet or rolling stock) or the mailer does not choose to containerize when not required to do so, an IMcb is not required on placards nor is submission of IMcb records required in eDoc.
Container barcodes are not required for a FCM mailing of less than 48 linear feet of letter trays or 16 linear feet of flat tubs.
Containers barcodes are required for mailings of FCM when:
○ The mailer has a customer service agreement (CSA).
○ The mailing is separated into different containers by destination.
○ The mailer chooses to containerize the mailing according to DMM 705.8.0.
○ The mail is entered at the dock of a processing facility and meets the following conditions:
Container barcodes are required for a Standard Mail, Periodicals, or BPM mailing when:
○ The mailing is more than 500 pounds of bundles/sacks.
○ The mailing is more than 72 linear feet of trays.
○ The mailing is separated into different destinations by container.
○ The mailing is required to be containerized under DMM 705.8.0.
○ The mailer chooses to containerize the mailing under DMM 705.8.0.
Effective January 26, 2014, when mailings are entered and full-service
•
•
•
•
•
To view final specifications and detailed information on the IMb, access RIBBS at
Effective January 26, 2014, when mailings are entered and full-service automation prices are claimed, mailers must use tray labels that bear 24-digit IMtb. An IMtb contains the following information:
•
•
•
•
•
•
To view the final specifications and detailed information on the IMtb, access RIBBS at
Mailers typically label containers of mail deposited with the Postal Service. For full-service, mailers must apply a unique IMcb to container placards and keep the barcode unique for at least 45 days from the date of mailing. This IMcb includes fields to identify the mailer and uniquely identify each container. To comply with the full-service standards, mailers must apply placards to all containers such as pallets, APCs, rolling stock, and gaylords separated by destination, according to the CSA or the pallet preparation standards in the DMM. Situations in which containers are not required are described above under the full-service requirements.
The IMcb has two formats. The format a mailer uses depends upon the MID assigned by the Postal Service.
The IMcb label specifications are available in two physical sizes for the IMcb barcode labels: One is the 8″ min x 11″ format available on RIBBS, and the other size is the 4″ x 7″ self-adhesive format, also available on RIBBS.
•
•
•
•
All mailers whose mail is verified at a detached mail unit (DMU)/BMEU and transported by the mailer or their agent to a USPS processing facility, including mailings entered at origin and plant-verified drop shipments (PVDS), are required to schedule appointments using the FAST system at postal facilities where applicable. Mailers may schedule appointments online using the FAST Web site or they may submit appointment requests through
By submitting documents electronically, mailers manage mailing data more effectively and avoid the creation of paper-based forms. Additionally, electronic submission of documents enables the Postal Service to capture efficiencies.
When entering full-service mailings, eDoc is required. A mailer's eDoc identifies the unique IMb applied to each mailpiece, tray, tub, sack, and container. It describes how mailpieces
The eDoc is transmitted to
Full-service mailings with fewer than 10,000 pieces do not require the submission of eDoc—only an electronic postage statement is required. These mailings may be electronically submitted using the Postal Wizard, Mail.XML, or Mail.dat. Mailings of fewer than 5,000 pieces can also be submitted using the IMsb tool.
For mailings of fewer than 10,000 pieces, when postage is affixed to each piece at the correct price or each piece is of identical weight and the mailpieces are separated by price, the serial number field of each IMb can be populated with a mailing serial number unique to the mailing but common to all pieces in the mailing. This unique mailing serial number must not be reused for a period of 45 days from the date of mailing. Mailers who enter such mailings are required to submit an electronic postage statement, instead of eDoc. Unique mailing serial numbers must be provided in the electronic documentation.
When full-service mailings with 10,000 or more pieces are entered, mailers are required to use Mail.dat or Mail.XML to electronically transmit mailing documentation and postage statements. eDoc must contain information about the unique ID applied to the mailpieces, placards, trays, tubs, sacks, and containers. Also, the information must describe how mailpieces are linked to handling units and how mailpieces and handling units are linked to containers.
In addition, when mailings are co-palletized, co-mingled, or combined in-house or at a different plant, eDoc that outlines the linkage among associated containers, trays, tubs, and sacks is required.
The four methods for submitting eDoc are described as follows:
Postal Wizard verifies completed information for an online postage statement and automatically populates the permit holder section of the postage statement based on the account number provided. It guides the user through items needed to complete the statement. Postal Wizard automatically calculates postage and validates submitted information. Once a postage statement is completed online, the electronic statement is submitted directly to the acceptance unit. For full-service mailings using the Postal Wizard, only the owner of the mailing permit receives start-the-clock feedback.
For detailed information about electronic mailing options, access RIBBS at
As part of the full-service program, the Postal Service is making the following information available through the online Postal Service BCG tool and
Address correction information is not available for Standard Mail flats paid at basic, high-density, high-density plus ECR prices or BPM flats paid at barcoded, presort DDU or barcoded, carrier-route prices.
The Postal Service adopts the following changes to the
Administrative practice and procedure, Postal Service.
Accordingly, 39 CFR part 111 is amended as follows:
5 U.S.C. 552(a); 13 U.S.C. 301–307; 18 U.S.C. 1692–1737; 39 U.S.C. 101, 401, 403, 404, 414, 416, 3001–3011, 3201–3219, 3403–3406, 3621, 3622, 3626, 3632, 3633, and 5001.
All pieces in a First-Class Mail automation mailing must meet full-service standards in 705.24.0 and:
e. Bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code that matches the delivery address and meet the standards in 202.5.0 and 708.4.0, whether on the piece or on an insert showing through an envelope window.
All pieces in an Enhanced Carrier Route or Nonprofit Enhanced Carrier Route Standard Mail mailing must:
g. Meet the requirements for automation letters in 201.3.0 and bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code matching the delivery address and meet the standards in 202.5.0 and 708.4.0, except for letters with simplified addresses or as provided in 6.1.2h. Letters mailed at automation carrier route (basic, high density, or saturation) prices must be in a mailing entered under full-service Intelligent Mail standards in 705.24.0. Pieces prepared with a simplified address format are exempt from the full-service, automation-compatibility, and barcode requirements.
In addition to the eligibility standards in 6.1, high density and high-density plus letter-size mailpieces must be in a full carrier route tray or in a carrier route bundle of 10 or more pieces prepared under 245.6.0. Except for pieces with a simplified address, only nonautomation high density and high-density plus letter prices apply when mailpieces are not: correctly barcoded with an Intelligent Mail barcode under 202.5.0 and 708.4.0, automation-compatible, and part of a full-service mailing under 705.24.0.
In addition to the eligibility standards in 6.1, saturation letter-size mailpieces must be in a full carrier route tray or in a carrier route bundle of 10 or more pieces prepared under 245.6.0. Except for pieces with a simplified address, only nonautomation saturation letter prices apply when mailpieces are not: correctly barcoded with an Intelligent Mail barcode under 202.5.0 and 708.4.0, automation-compatible, and part of a full-service mailing under 705.24.0.
All pieces in a Regular Standard Mail or Nonprofit Standard Mail automation mailing must meet full-service standards in 705.24.0 and:
e. Bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code, matching the delivery address and meeting the standards in 202.5.0 and 708.4.0, either on the piece or on an insert showing through an envelope window.
All pieces in a First-Class Mail automation flats mailing must meet full-service standards in 705.24.0 and:
e. Bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code, matching the delivery address and meet the standards in 302.5.0 and 708.4.0, either on the piece or on an insert showing through an envelope window.
All pieces in a Regular Standard Mail or Nonprofit Standard Mail automation mailing must meet full-service standards in 705.24.0 and:
e. Bear an accurate unique Intelligent Mail barcode encoded with the correct
delivery point routing code, matching the delivery address and meet the standards in 302.5.0 and 708.4.0, either on the piece or on an insert showing through an envelope window.
* * * Price categories are as follows:
d. Barcoded Discount—Flats. The barcoded discount applies to BPM flats that meet the requirements for automation flats in 301.3.0, bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code, and are part of a full-service mailing under 705.24.0. See 6.1 for more information.
The barcode discount applies only to BPM flat-size pieces meeting the standards under 301.3.0 and bearing a unique Intelligent Mail barcode encoded with the correct delivery point routing code, matching the delivery address, and meeting the standards in 302.5.0 and 708.4.0. The pieces must be part of a full-service (under 705.24.0) nonpresorted mailing of 50 or more flat-size pieces or part of a full-service Presorted mailing of at least 300 BPM flats prepared under 365.7.0, 705.8.0, 705.14.0, and 705.24.0. The barcode discount is not available for flats mailed at Presorted DDU prices or carrier route prices.
Participation in Intelligent Mail barcode (IMb) Tracing service is available at no charge without a subscription. Requirements for participation in IMb Tracing include:
• Use of an IMb on mailpieces entered as part of a full-service mailing under 705.24.0.
• Use of a Mailer Identifier that has been registered (through the Business Customer Gateway, accessible on
• Verification by the Postal Service that the IMb as printed meets all applicable postal standards.
Full-service automation mailings may include automation-compatible pieces without barcodes, with POSTNET barcodes, or with non-full-service Intelligent Mail barcodes, but these pieces will not be used to meet the eligibility standards for full-service or receive associated benefits. Full-service automation letters must not be comingled in the same tray with pieces without barcodes, pieces with POSTNET barcodes, or pieces with an IMb without a delivery point barcode. Full-service automation mailpieces may be comingled in a tray with non-full-service eligible pieces (automation-compatible under 201.3.0) with an IMb containing a delivery point barcode.
First-Class Mail, Periodicals, and Standard Mail letters and flats meeting eligibility requirements for automation or carrier route prices (except for Standard Mail ECR saturation flats), and Bound Printed Matter flats (except for Presorted DDU-entered and carrier route flats) are potentially eligible for full-service prices. All pieces entered under full-service pricing must:
c. Be part of a mailing using unique Intelligent Mail container barcodes on
Mailing documentation, when required, must associate each mailpiece to a corresponding tray or sack, or to a logical tray or sack, as described in 24.4.4.
Mailing documentation, when required, must associate each mailpiece (and tray or sack, if applicable) to a corresponding container (or a logical container) as described in 24.4.4, unless otherwise authorized by the USPS.
Mailers must electronically submit postage statements and mailing documentation to the
For mailings of fewer than 10,000 pieces, when postage is affixed to each piece at the correct price or each piece is of identical weight and the mailpieces are separated by price, the serial number field of each Intelligent Mail barcode can be populated with a mailing serial number that is unique to the mailing but common to all pieces in the mailing. This unique mailing serial number must not be reused for a period of 45 days from the date of mailing. These mailings are not required to submit electronic documentation for full-service, only an electronic postage statement. Unique mailing serial numbers must be populated in the Postal Wizard entry screen field or in the electronic documentation.
In addition to other requirements in 6.0, carrier route letters and flats eligible for full-service Intelligent Mail prices and address correction benefits under 705.24 must:
d. * * * Letters or flats with Intelligent Mail barcodes entered under the full-service automation option must also be part of mailings that meet the standards in 705.24.
All pieces in a Periodicals barcoded (automation) mailing must meet the full-service standards in 705.24.0 and:
c. Bear an accurate unique Intelligent Mail barcode encoded with the correct delivery point routing code, matching the delivery address, and meeting the standards in 202.5.0 (for letters), 302.4.0 (for flats), and 708.4.0, either on the piece or on an insert showing through a window.
All pieces entered under the full-service automation standards must:
b. Be part of a mailing that meets the standards in 705.24.0.
Intelligent Mail tray labels are the USPS-approved method to encode routing, content, origin, and mailer information on trays and sacks. Intelligent Mail tray labels are designed for optimum use with Intelligent Mail barcoded mail and have the capacity to provide unique identification throughout postal processing, but are required for use on all trays and sacks in presorted mailings.
a. Intelligent Mail container placards are not required for small mailings of Standard Mail, Periodicals, and Bound Printed Matter letters and flats when entered at a BMEU, if the mailing is less than 500 pounds of bundles or sacks and fewer than 72 linear feet of trays.
b. Intelligent Mail container placards are not required when entering mail at a co-located BMEU within the service area where mail is entered, if the mailing consists of 100 but less than 250 pounds of bundles or sacks, and at least 12 but fewer than 35 linear feet of trays.
The destination line must meet these standards:
a.
The origin line must appear below the content line, except as allowed under 6.3.4 and 6.2.5a and 6.2.5b. * * *
Intelligent Mail tray labels are 2-inch labels used on trays and sacks to provide unique identification within postal processing. 24-digit Intelligent Mail tray labels include only a 24-digit barcode printed in International Symbology Specification (ISS) Code 128 subset C symbology (see Exhibit 6.3.3). Intelligent Mail tray labels also include a human readable field designed to indicate the carrier route for carrier route mailings, display an “AUTO” indicator text for automation mailings, or remain blank for nonautomation mailings. Mailers using Intelligent Mail tray labels must print labels in the 24-digit Intelligent Mail tray label format. Detailed specifications for the tray label and barcode formats are at
We will publish an amendment to 39 CFR part 111 to reflect these changes.
Environmental Protection Agency (EPA).
Withdrawal of direct final rule.
EPA published a direct final rule, Air Quality: Revision to Definition of Volatile Organic Compounds—Exclusion of
Effective April 18, 2013, the EPA withdraws the direct final rule amendments published at 78 FR 11101 on February 15, 2013.
David Sanders, Office of Air Quality Planning and Standards, Air Quality Policy Division, Mail Code C539–01, Research Triangle Park, NC 27711; telephone: (919) 541–3356; fax: (919) 541–0824; email address:
EPA published in the
The direct final rulemaking action announced that the direct final rule would be withdrawn if EPA received any adverse comments by April 1, 2013. The EPA received one adverse comment in a timely manner. With this notice, EPA is withdrawing the February 15, 2013, direct final rulemaking action pertaining to the exemption of Solstice
Environmental protection, Administrative practice and procedure, Air pollution control, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
In Title 40 of the Code of Federal Regulations, Parts 96 to 99, revised as of July 1, 2012, on page 768, in § 98.226, in paragraph (n) introductory text, the last sentence is removed.
Federal Communications Commission.
Final rule.
This document amends our rules concerning commercial radio operator licenses for maritime and aviation radio stations in order to reduce administrative burdens in the public's interest.
Effective May 20, 2013, except for amendments to §§ 1.913(d)(1)(vi), 13.9(c), and 13.13(c), which contain information collection requirements that are not effective until approved by the Office of Management and Budget (“OMB”). The FCC will publish a document in the
Stana Kimball, Mobility Division, Wireless Telecommunications Bureau, (202) 418–1306, TTY (202) 418–7233.
This is a summary of the Federal Communications Commission's
1. The Federal Communications Commission's (Commission) rules require that a person who operates, maintains, or conducts the mandatory inspection of certain maritime and aviation radio stations hold an appropriate commercial radio operator license. The Commission initiated this proceeding to amend the part 13 Commercial Radio Operator rules, and related rules in parts 0, 1, 80, and 87 regarding certain functions performed by licensed commercial radio operators, to determine which rules could be clarified, streamlined, or eliminated in order to reduce administrative burdens and make the rules easier to use. The Commission takes the following significant actions in the
2. This document contains modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104–13. It has been submitted to the Office of Management and Budget (OMB) for review under section 3507(d) of the PRA. OMB, the general public, and other Federal agencies are invited to comment on the new or modified information collection requirements contained in this proceeding. In addition, the Commission notes that pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107–198, see 44 U.S.C. 3506(c)(4), it previously sought specific comment on how it might further reduce the information collection burden for small business concerns with fewer than 25 employees.
3. In the present document, the Commission has assessed the effects of our requirements that COLEMs filing applications on behalf of applicants submit the information electronically, and believe the burden will be minimal. Therefore, we find that these modified information collection requirements will not impose a substantial burden on businesses with fewer than 25 employees.
4. The Commission will send a copy of this
5. As required by the Regulatory Flexibility Act of 1980, as amended (RFA), an Initial Regulatory Flexibility Analysis (IRFA) was incorporated in the
6. We believe it is appropriate to review our regulations relating to commercial radio operators to determine which rules can be clarified, streamlined or eliminated. In this
7. There were no comments that specifically addressed the IRFA. Nonetheless, we have considered the potential impact of the rules adopted herein on small entities, and conclude that such impact would be minimal, in terms of measurable economic costs associated with compliance with the rules.
8. The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the rules adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms
9. Commercial radio licenses are issued only to individuals. Individuals are not “small entities” under the RFA.
10. Individual licensees are tested by COLEMs. The Commission has not developed a definition for a small business or small organization that is applicable for COLEMs. All or almost all of the nine COLEM organizations would appear to meet the RFA definition for small business or small organization.
11. COLEMs would be required to retain certain records for three years, instead of the existing one-year retention period; but would submit that information to the Commission only upon request, instead submitting it on a regular schedule as occurs presently. This would effectively eliminate the existing economic burden related to the reporting requirement, and it would not create any additional measurable economic burden in connection with the extended recordkeeping requirement. COLEMs would also be required to provide examination results to examinees within three business days, and to use electronic filing when submitting applications on behalf of examinees. Because almost all COLEMs already meet both of these requirements, this also would create no additional economic burden on COLEMs.
12. The RFA requires an agency to describe the steps it has taken to minimize the significant economic impact on small entities consistent with the stated objectives of applicable statutes, including a statement of the factual, policy, and legal reasons for selecting the alternative adopted in the final rule and why each one of the other significant alternatives to the rule considered by the agency which affect the impact on small entities was rejected.
13. We believe the changes adopted in this
14. The Commission will send a copy of the
Organization and functions (Government agencies).
Administrative practice and procedure, Communications common carriers, Telecommunications.
Communications equipment, Radio.
Communications equipment, Radio.
Air transportation, Communications equipment, Radio.
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR parts 0, 1, 13, 80, and 87 as follows:
Secs. 5, 48 Stat. 1068, as amended; 47 U.S.C. 155.
(e) Coordinate with and assist the Wireless Telecommunications Bureau with respect to the Commission's privatized ship radio inspection program.
(j) Administers the Commission's commercial radio operator program (part 13 of this chapter); the Commission's program for registration, construction, marking and lighting of antenna structures (part 17 of this chapter), and the Commission's privatized ship radio inspection program (part 80 of this chapter).
(r)(1) Extends the Communications Act Safety Radiotelephony Certificate for a period of up to 90 days beyond the specified expiration date.
(2) Grants emergency exemption requests, extensions or waivers of inspection to ships in accordance with applicable provisions of the Communications Act, the Safety Convention, the Great Lakes Agreement or the Commission's rules.
(b) Application filing procedures for commercial radio operator licenses are set forth in part 13 of this chapter.
15 U.S.C. 79 et seq.; 47 U.S.C. 151, 154(i), 154(j), 155, 157, 225, 303(r), and 309.
Whenever grounds exist for suspension of an operator license, as provided in § 303(m) of the Communications Act, the Chief of the Wireless Telecommunications Bureau, with respect to amateur and commercial radio operator licenses, may issue an order suspending the operator license. No order of suspension of any operator's license shall take effect until 15 days' notice in writing of the cause for the proposed suspension has been given to the operator licensee, who may make written application to the Commission at any time within the said 15 days for a hearing upon such order. The notice to the operator licensee shall not be effective until actually received by him, and from that time he shall have 15 days in which to mail the said application. In the event that physical conditions prevent mailing of the application before the expiration of the 15-day period, the application shall then be mailed as soon as possible thereafter, accompanied by a satisfactory explanation of the delay. Upon receipt by the Commission of such application for hearing, said order of suspension shall be designated for hearing by the Chief, Wireless Telecommunications Bureau and said suspension shall be held in abeyance until the conclusion of the hearing. Upon the conclusion of said hearing, the Commission may affirm, modify, or revoke said order of suspension. If the license is ordered suspended, the operator shall send his operator license to the Mobility Division, Wireless Telecommunications Bureau, in Washington, DC, on or before the effective date of the order, or, if the effective date has passed at the time notice is received, the license shall be sent to the Commission forthwith.
(d) * * *
(1) * * *
(vi) Part 13 Commercial Radio Operators (individual applicants only; commercial operator license examination managers must file electronically, see § 13.13(c) of this part); and
Secs. 4, 303, 48 Stat. 1066, 1082, as amended; 47 U.S.C. 154, 303.
Rules that require FCC station licensees to have certain transmitter operation, maintenance, and repair duties performed by a commercial radio operator are contained in parts 80 and 87 of this chapter.
The revisions and additions read as follows:
(b) There are twelve types of commercial radio operator licenses, certificates and permits (licenses). The license's ITU classification, if different from its name, is given in parentheses.
(1) First Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new First Class Radiotelegraph Operator's Certificates will be accepted for filing.
(2) Second Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new Second Class Radiotelegraph Operator's Certificates will be accepted for filing.
(3) Third Class Radiotelegraph Operator's Certificate (radiotelegraph operator's special certificate). Beginning May 20, 2013, no applications for new Third Class Radiotelegraph Operator's Certificates will be accepted for filing.
(4) Radiotelegraph Operator License.
(c) There are three license endorsements affixed by the FCC to provide special authorizations or restrictions. Endorsements may be affixed to the license(s) indicated in parentheses.
(1) Ship Radar Endorsement (First and Second Class Radiotelegraph Operator's Certificates, Radiotelegraph Operator License, General Radiotelephone Operator License, GMDSS Radio Maintainer's License).
(2) Six Months Service Endorsement (First and Second Class Radiotelegraph Operator's Certificates, Radiotelegraph Operator License)
(3) Restrictive endorsements relating to physical disability, English language or literacy waivers, or other matters (all licenses).
(a) A First Class Radiotelegraph Operator's Certificate conveys all of the operating authority of the Second Class Radiotelegraph Operator's Certificate, the Third Class Radiotelegraph Operator's Certificate, the Radiotelegraph Operator License, the Restricted Radiotelephone Operator Permit, and the Marine Radio Operator Permit.
(b) A Radiotelegraph Operator License conveys all of the operating authority of the Second Class Radiotelegraph Operator's Certificate, which conveys all of the operating authority of the Third Class Radiotelegraph Operator's Certificate, the Restricted Radiotelephone Operator Permit, and the Marine Radio Operator Permit.
(d) A General Radiotelephone Operator License conveys all of the operating authority of the Marine Radio Operator Permit and the Restricted Radiotelephone Operator Permit.
(e) A GMDSS Radio Operator's License conveys all of the operating authority of the Marine Radio Operator Permit and the Restricted Radiotelephone Operator Permit.
(f) A GMDSS Radio Maintainer's License conveys all of the operating authority of the General Radiotelephone Operator License, the Marine Radio Operator Permit, and the Restricted Radiotelephone Operator Permit.
(g) A Marine Radio Operator Permit conveys all of the authority of the Restricted Radiotelephone Operator Permit.
(b) Each application for a new General Radiotelephone Operator License, Marine Radio Operator Permit, Radiotelegraph Operator License, Ship Radar Endorsement, Six Months Service Endorsement, GMDSS Radio Operator's License, Restricted GMDSS Radio Operator's License, GMDSS Radio Maintainer's License, GMDSS Radio Operator/Maintainer License, Restricted
(c) Each application for a new General Radiotelephone Operator License, Marine Radio Operator Permit, Radiotelegraph Operator License, Ship Radar Endorsement, GMDSS Radio Operator's License, Restricted GMDSS Radio Operator's License, GMDSS Radio Maintainer's License, or GMDSS Radio Operator/Maintainer License must be accompanied by the required fee, if any, and submitted in accordance with § 1.913 of this chapter. The application must include an original PPC(s) from a COLEM(s) showing that the applicant has passed the necessary examination Element(s) within the previous 365 days when the applicant files the application. If a COLEM files the application on behalf of the applicant, an original PPC(s) is not required. However, the COLEM must keep the PPC(s) on file for a period of 1 year. When acting on behalf of qualified examinees, the COLEM must forward all required data to the FCC electronically.
(d) * * *
(1) An unexpired (or within the grace period) FCC-issued commercial radio operator license: Except as noted in paragraph (d)(3) of this section, the written examination and telegraphy Element(s) required to obtain the license held;
(2) An expired or unexpired FCC-issued Amateur Extra Class operator license grant granted before April 15, 2000: Telegraphy Elements 1 and 2; and
(3) An FCC-issued Third Class Radiotelegraph Operator's Certificate that was renewed as a Marine Radio Operator Permit (
(f) * * *
(4) The applicant held a FCC-issued First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License during this entire six month qualifying period; and
In accordance with § 1.923 of this chapter, all applicants (except applicants for a Restricted Radiotelephone Operator Permit or a Restricted Radiotelephone Operator Permit–Limited Use) must specify an address where the applicant can receive mail delivery by the United States Postal Service. Suspension of the operator license may result when correspondence from the FCC is returned as undeliverable because the applicant failed to provide the correct mailing address.
(a) An eligible person may hold more than one commercial operator license.
(a) Each application to renew a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Third Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License must be made on FCC Form 605. The application must be accompanied by the appropriate fee and submitted in accordance with § 1.913 of this chapter. Beginning May 20, 2013, First and Second Class Radiotelegraph Operator's Certificates will be renewed as Radiotelegraph Operator Licenses, and Third Class Radiotelegraph Operator's Certificates will be renewed as Marine Radio Operator Permits.
(b) If a license expires, application for renewal may be made during a grace period of five years after the expiration date without having to retake the required examinations. The application must be accompanied by the required fee and submitted in accordance with § 1.913 of this chapter. During the grace period, the expired license is not valid. A license renewed during the grace period will be effective as of the date of the renewal. Licensees who fail to renew their licenses within the grace period must apply for a new license and take the required examination(s). Beginning May 20, 2013, no applications for new First, Second, or Third Class Radiotelegraph Operator's Certificates will be accepted for filing.
(c) Each application involving a change in operator class must be filed on FCC Form 605. Each application for a commercial operator license involving a change in operator class must be accompanied by the required fee, if any, and submitted in accordance with § 1.913 of this chapter. The application must include an original PPC(s) from a COLEM(s) showing that the applicant has passed the necessary examination Element(s) within the previous 365 days when the applicant files the application. If a COLEM files the application on behalf of the applicant, an original PPC(s) is not required. However, the COLEM must keep the PPC(s) on file for a period of 1 year. When acting on behalf of qualified examinees, the COLEM must forward all required data to the FCC electronically.
(d) Provided that a person's commercial radio operator license was not revoked, or suspended, and is not the subject of an ongoing suspension proceeding, a person holding a General Radiotelephone Operator License, Marine Radio Operator Permit, First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Third Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator License, GMDSS Radio Operator's License, GMDSS Radio Maintainer's License, or GMDSS Radio Operator/Maintainer License, who has an application for another commercial radio operator license which has not yet been acted upon pending at the FCC and who holds a PPC(s) indicating that he or she passed the necessary examination(s) within the previous 365 days, is authorized to exercise the rights and privileges of the license for which the application is filed. This temporary conditional operating authority is valid for a period of 90 days from the date the application is received. This temporary conditional operating authority does not relieve the licensee of the obligation to comply with the certification requirements of the Standards of Training, Certification and Watchkeeping (STCW) Convention. The FCC, in its discretion, may cancel this temporary conditional operating authority without a hearing.
(e) An applicant will be given credit for an examination element as specified below:
(1) An unexpired (or within the grace period) FCC-issued commercial radio operator license: Except as noted in paragraph (e)(3) of this section, the written examination and telegraphy Element(s) required to obtain the license held;
(2) An expired or unexpired FCC-issued Amateur Extra Class operator license grant granted before April 15, 2000: Telegraphy Elements 1 and 2; and
(3) An FCC-issued Third Class Radiotelegraph Operator's Certificate that was renewed as a Marine Radio Operator Permit (
First Class Radiotelegraph Operator's Certificates, Second Class Radiotelegraph Operator's Certificates, and Third Class Radiotelegraph Operator's Certificates are normally valid for a term of five years from the date of issuance. All other commercial radio operator licenses are normally valid for the lifetime of the holder.
(a) Each licensee or permittee whose original document is lost, mutilated, or destroyed may request a replacement. The application must be accompanied by the required fee and submitted to the address specified in part 1 of the rules.
(b) Each application for a replacement General Radiotelephone Operator License, Marine Radio Operator Permit, First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Third Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator Certificate, GMDSS Radio Operator's License, Restricted GMDSS Radio Operator's License, GMDSS Radio Maintainer's License, or GMDSS Radio Operator/Maintainer License must be made on FCC Form 605 and must include a written explanation as to the circumstances involved in the loss, mutilation, or destruction of the original document.
(c) Each application for a replacement Restricted Radiotelephone Operator Permit or Restricted Radiotelephone Operator Permit-Limited Use must be on FCC Form 605.
(b) * * *
(3) The class, serial number, and expiration date (if applicable) of the license when the FCC has issued the operator a license; or the PPC serial number(s) and date(s) of issue when the operator is awaiting FCC action on an application.
(b) * * *
(1) Radiotelegraph Operator License.
(i) Telegraphy Elements 1 and 2;
(ii) Written Elements 1 and 6.
(a) * * *
(1) Element 1: Basic radio law and operating practice with which every maritime radio operator should be familiar. Questions concerning provisions of laws, treaties, regulations, and operating procedures and practices generally followed or required in communicating by means of radiotelephone stations.
(2) Element 3: General radiotelephone. Questions concerning electronic fundamentals and techniques required to adjust, repair, and maintain radio transmitters and receivers at stations licensed by the FCC in the aviation and maritime radio services.
(d) Passing a telegraphy examination. Passing a telegraphy receiving examination is adequate proof of an examinee's ability to both send and receive telegraphy. The COLEM, however, may also include a sending segment in a telegraphy examination.
(1) To pass a receiving telegraphy examination, an examinee is required to receive correctly the message by ear, for a period of 1 minute without error at the rate of speed specified in § 13.203(b).
(2) To pass a sending telegraphy examination, an examinee is required to send correctly for a period of one minute at the rate of speed specified in § 13.203(b).
(g) No applicant who is eligible to apply for any commercial radio operator license shall, by reason of any physical disability, be denied the privilege of applying and being permitted to attempt to prove his or her qualifications (by examination if examination is required) for such commercial radio operator license in accordance with procedures established by the COLEM.
(e) Within 3 business days of completion of the examination Element(s), the COLEM must provide the results of the examination to the examinee and the COLEM must issue a PPC to an examinee who scores a passing grade on an examination Element.
Each COLEM recovering fees from examinees must maintain records of expenses and revenues, frequency of examinations administered, and examination pass rates. Records must cover the period from January 1 to December 31 of the preceding year and must be submitted as directed by the Commission. Each COLEM must retain records for 3 years and the records must be made available to the FCC upon request.
Secs. 4, 303, 307(e), 309, and 332, 48 Stat. 1066, 1082, as amended; 47 U.S.C. 154, 303, 307(e), 309, and 332, unless otherwise noted. Interpret or apply 48 Stat. 1064–1068, 1081–1105, as amended; 47 U.S.C. 151–155, 301–609; 3 UST 3450, 3 UST 4726, 12 UST 2377.
(a) * * *
(1) * * *
Nothing in this section prohibits Commission inspectors from inspecting ships. The mandatory inspection of U.S. vessels must be conducted by an FCC-licensed technician holding an FCC General Radiotelephone Operator License, GMDSS Radio Maintainer's License, Second Class Radiotelegraph Operator's Certificate, First Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License in accordance with the following table:
(b) Inspection and certification of a ship subject to the Great Lakes Agreement. The FCC will not inspect Great Lakes Agreement vessels. An inspection and certification of a ship subject to the Great Lakes Agreement must be made by a technician holding one of the following: an FCC General Radiotelephone Operator License, a GMDSS Radio Maintainer's License, a Second Class Radiotelegraph Operator's Certificate, a First Class Radiotelegraph Operator's Certificate, or a Radiotelegraph Operator License. The certification required by § 80.953 must be entered into the ship's log. The technician conducting the inspection and providing the certification must not be the vessel's owner, operator, master, or an employee of any of them. Additionally, the vessel owner, operator, or ship's master must certify that the inspection was satisfactory. There are no FCC prior notice requirements for any inspection pursuant to § 80.59(b).
(b) * * *
(9) T–3. Third Class Radiotelegraph Operator's Certificate (radiotelegraph operator's special certificate). Beginning May 20, 2013, no applications for new Third Class Radiotelegraph Operator's Certificates will be accepted for filing.
(10) T–2. Second Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new Second Class Radiotelegraph Operator's Certificates will be accepted for filing.
(11) T–1. First Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new First Class Radiotelegraph Operator's Certificates will be accepted for filing.
(12) T. Radiotelegraph Operator License.(c) * * *
(1) Ship Radar endorsement (First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator License, General Radiotelephone Operator License).
(2) Six Months Service endorsement (First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator License).
(3) Restrictive endorsements; relating to physical disabilities, English language or literacy waivers, or other matters (all licenses).
A
(a) Each telegraphy passenger ship equipped with a radiotelegraph station in accordance with Part II of Title III of the Communications Act must carry two radio officers holding a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License.
(b) Each cargo ship equipped with a radiotelegraph station in accordance with Part II of Title II of the Communications Act and which has a radiotelegraph auto alarm must carry a radio officer holding a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License who has had at least six months service as a radio officer on board U.S. ships. If the radiotelegraph station does not have an auto alarm, a second radio officer who holds a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License must be carried.
The operator of maritime radio equipment other than T–1, T–2, T, or G licensees must not:
(a) All adjustments of radio transmitters in any radiotelephone station or coincident with the installation, servicing, or maintenance of such equipment which may affect the proper operation of the station, must be performed by or under the immediate supervision and responsibility of a person holding a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator
(b) Only persons holding a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, or Radiotelegraph Operator License must perform such functions at radiotelegraph stations transmitting Morse code.
(b) * * *
(3) Except as provided in paragraph (b)(4) of this section, programming of authorized channels must be performed only by a person holding a First Class Radiotelegraph Operator's Certificate, Second Class Radiotelegraph Operator's Certificate, Radiotelegraph Operator License, or General Radiotelephone Operator License using any of the following procedures:
5. The requirements for having the GMDSS Master Plan, NGA Publication 117, Admiralty List of Radio Signals or IMO Circ. 7 are satisfied by having any one of those four documents.
(e) * * *
(3) The time of any inadvertent transmissions of distress, urgency and safety signals including the time and method of cancellation.
(4) An entry that pre-departure equipment checks were satisfactory and that required publications are on hand. Daily entries of satisfactory tests to ensure the continued proper functioning of GMDSS equipment shall be made.
(5) A daily statement about the condition of the required radiotelephone equipment, as determined by either normal communication or test communication;
(6) A weekly entry that:
(i) The proper functioning of digital selective calling (DSC) equipment has been verified by actual communications or a test call;
(ii) The portable survival craft radio gear and radar transponders have been tested; and
(iii) The EPIRBs have been inspected.
(7) An entry at least once every thirty days that the batteries or other reserve power sources have been checked and are functioning properly.
(8) Results of required equipment tests, including specific gravity of lead-acid storage batteries and voltage reading of other types of batteries provided as a part of the compulsory installation;
(9) Results of inspections and tests of compulsorily fitted lifeboat radio equipment;
(10) When the master is notified about improperly operating radiotelephone equipment.
(11) At the beginning of each watch, the Officer of the Navigational Watch, or GMDSS Operator on watch, if one is provided, shall ensure that the navigation receiver is functioning properly and is interconnected to all GMDSS alerting devices which do not have integral navigation receivers, including: VHF DSC, MF DSC, satellite EPIRB and HF DSC or INMARSAT SES. On a ship without integral or directly connected navigation receiver input to GMDSS equipment, the Officer of the Navigational Watch, or GMDSS Operator on watch, shall update the embedded position in each equipment. An appropriate log entry of these actions shall be made.
(12) An entry describing any malfunctioning GMDSS equipment and another entry when the equipment is restored to normal operation.
(13) A GMDSS radio log entry shall be made whenever GMDSS equipment is exchanged or replaced (ensuring that ship MMSI identifiers are properly updated in the replacement equipment), when major repairs to GMDSS equipment are accomplished, and when annual GMDSS inspections are conducted.
(f)
(1) Radiotelephony stations subject to the Communications Act and/or the Safety Convention must record entries indicated by paragraphs (e)(1) through (e)(13) of this section. Additionally, the radiotelephone log must provide an easily identifiable, separate section relating to the required inspection of the ship's radio station. Entries must be made in this section giving at least the following information.
(i) * * *
(E) The inspector's signed and dated certification that the vessel meets the requirements of the Communications Act and, if applicable, the Safety Convention and the Bridge-to-Bridge Act contained in subparts R, S, U, or W of this part and has successfully passed the inspection.
(2) Radiotelephony stations subject to the Great Lakes Agreement and the Bridge-to-Bridge Act must record entries indicated by paragraphs (e)(1), (3), (5), (6), (7), (8), (10), (11), and (13), and of this section. Additionally, the radiotelephone log must provide an easily identifiable, separate section relating to the required inspection of the ship's radio station. Entries must be made in this section giving at least the following information:
(3) Radiotelephony stations subject to the Bridge-to-Bridge Act must record entries indicated by paragraphs (e)(1), (3), (5) (6), (7), (10), and (11) of this section.
(b) * * *
(2) U.S. NGA Publication 117 may be purchased from Superintendent of Documents, P.O. Box 371954, Pittsburgh, PA 15250–7954, telephone 202–512–1800.
(b) An inspection and certification of a ship subject to the Great Lakes Agreement must be made by a technician holding one of the following: a General Radiotelephone Operator License, a GMDSS Radio Maintainer's License, a Radiotelegraph Operator License, a Second Class Radiotelegraph Operator's Certificate, or a First Class Radiotelegraph Operator's Certificate. Additionally, the technician must not be the vessel's owner, operator, master, or an employee of any of them. The results of the inspection must be recorded in the ship's radiotelephone log and include:
The bridge-to-bridge radiotelephone station will be inspected on vessels subject to regular inspections pursuant to the requirements of Parts II and III of Title II of the Communications Act, the Safety Convention or the Great Lakes Agreement at the time of the regular inspection. If after such inspection, the Commission determines that the Bridge-to-Bridge Act, the rules of the Commission and the station license are met, an endorsement will be made on the appropriate document. The validity of the endorsement will run concurrently with the period of the regular inspection. Each vessel must carry a certificate with a valid endorsement while subject to the Bridge-to-Bridge Act. All other bridge-to-bridge stations will be inspected from time to time. An inspection of the bridge-to-bridge station on a Great Lakes Agreement vessel must normally be made at the same time as the Great Lakes Agreement inspection is conducted by a technician holding one of the following: a General Radiotelephone Operator License, a GMDSS Radio Maintainer's License, a Radiotelegraph Operator License, a Second Class Radiotelegraph Operator's Certificate, or a First Class Radiotelegraph Operator's Certificate. Additionally, the technician must not be the owner, operator, master, or an employee of any of them. Ships subject to the Bridge-to-Bridge Act may, in lieu of an endorsed certificate, certify compliance in the station log required by § 80.409(f).
(b) Ships must carry either the most recent edition of the IMO publication entitled GMDSS Master Plan of Shore-Based Facilities, the U.S. NGA Publication 117, or the Admiralty List of Radio Signals Volume 5 Global Maritime Distress and Safety System. Notice of new editions will be published on the Commission's Wireless Telecommunications Bureau Web page under “Marine Services” and information will be provided about obtaining the new document.
(b) Homing signals are those locating signals which are transmitted by mobile units in distress, or by survival craft, for the purpose of providing searching units with a signal that can be used to determine the bearing to the transmitting stations.
47 U.S.C. 154, 303 and 307(e), unless otherwise noted.
(b) * * *
(1) T–1. First Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new First Class Radiotelegraph Operator's Certificates will be accepted for filing.
(2) T–2. Second Class Radiotelegraph Operator's Certificate. Beginning May 20, 2013, no applications for new Second Class Radiotelegraph Operator's Certificates will be accepted for filing.
(3) T–3. Third Class Radiotelegraph Operator's Certificate (radiotelegraph operator's special certificate). Beginning May 20, 2013, no applications for new Third Class Radiotelegraph Operator's Certificates will be accepted for filing.
(4) T. Radiotelegraph Operator License.
National Highway Traffic Safety Administration (NHTSA), Department of Transportation (DOT).
Final rule.
National Highway Traffic Safety Administration (NHTSA), Department of Transportation (DOT) is updating its regulations. These regulations govern the organization of the National Highway Traffic Safety Administration and delegations of authority from the Administrator to Agency officers including the Deputy Administrator, Chief Counsel, and Senior Associate Administrators. This rule is a publication of delegations made by the Administrator to other Agency officials.
This rule is effective April 18, 2013.
Ms. Dana Sade, Office of the Chief Counsel, National Highway Traffic Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. Telephone: (202) 366–1834.
This final rule updates the Code of Federal Regulations (CFR) sections that set forth the organization of the National Highway Traffic Safety Administration (NHTSA) and delegations of authority from the NHTSA Administrator to other Departmental officials including the Deputy Administrator, Chief Counsel, and Senior Associate Administrators. The purpose of this rule is to provide a road map to the public and government officials regarding how NHTSA operates, which office is responsible for which tasks, and the authority pursuant to which Agency offices act.
The regulations set forth in 49 CFR Part 501 are outdated and do not accurately reflect how NHTSA operates. For example, Part 501 still references an Executive Director, a position that no longer exists within the Agency. These and other inaccuracies in Part 501 create unnecessary confusion.
This rule amends Part 501 in three ways. First, it removes positions that are outdated and no longer exist within the Agency. Second, it updates the Administrator's delegations to reflect new statutory responsibilities and organizational changes within the Agency. Third, it clarifies the text and updates citations in Part 501 to increase transparency, accessibility, and readability.
This final rule does not impose substantive requirements. It simply updates the CFR to represent the current statutory and organizational posture of the Agency. The final rule is ministerial in nature and relates only to Agency management, organization, procedure, and practice. Therefore, the Agency has determined that notice and comment are unnecessary and that the rule is exempt from prior notice and comment requirements under 5 U.S.C. 553(b)(3)(A). As these changes will not have a substantive impact on the public, the Agency does not expect to receive significant comments on the substance of the rule. Therefore, the Department finds that there is good cause under 5 U.S.C. 553(d)(3) to make this rule effective less than 30 days after publication in the
The final rule is not considered a significant regulatory action under Executive Order 12866 and DOT Regulatory Policies and Procedures (44 FR 11034). It was not reviewed by the Office of Management and Budget. There are no costs associated with this rule.
This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). This final rule does not have a substantial direct effect on, or sufficient federalism implications for, the States, nor would it limit the policymaking discretion of the States. Therefore, the consultation requirements of Executive Order 13132 do not apply.
This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”). Because this final rule does not significantly or uniquely affect the
Because no notice of proposed rulemaking is required for this rule under the Administrative Procedure Act, 5 U.S.C. 553, the provisions of the Regulatory Flexibility Act (5 U.S.C. 601
This rule contains no information collection requirements under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520).
NHTSA has determined that the requirements of Title II of the Unfunded Mandates Reform Act of 1995 do not apply to this rulemaking.
Authority delegations (Government agencies), Organization and functions (Government agencies).
In consideration of the foregoing, NHTSA revises Title 49, Part 501 of the Code of Regulations to read as follows:
49 U.S.C. 105 and 322, and delegations of authority at 49 CFR 1.95.
This part describes the organization of the National Highway Traffic Safety Administration (NHTSA) through the Deputy Administrator, Chief Counsel, Senior Associate Administrator, Associate Administrator, Regional Administrator and Staff Office Director levels and provides for the performance of duties imposed on, and the exercise of powers vested in, the Administrator of the NHTSA (hereafter referred to as the “Administrator”).
The Administrator is delegated authority by the Secretary of Transportation (49 CFR 1.95) to:
(a) Carry out the following chapters or sections of Title 49 of the United States Code:
(1) Chapter 301—Motor Vehicle Safety.
(2) Chapter 303—National Driver Register.
(3) Chapter 321—General.
(4) Chapter 323—Consumer Information.
(5) Chapter 325—Bumper Standards.
(6) Chapter 327—Odometers.
(7) Chapter 329—Automobile Fuel Economy.
(8) Chapter 331—Theft Prevention.
(9) Section 20134(a), with respect to the laws administered by the National Highway Traffic Safety Administrator pertaining to highway, traffic and motor vehicle safety.
(b) Carry out 23 U.S.C. chapter 4, Highway Safety, as amended, except for section 409.
(c) Exercise the authority vested in the Secretary by section 210(2) of the Clean Air Act, as amended (42 U.S.C. 7544(2)).
(d) Carry out the provisions of 23 U.S.C. 313, Buy America.
(e) Administer the following sections of Title 23, United States Code, in coordination with the Federal Highway Administrator as appropriate:
(1) Section 153.
(2) Section 154.
(3) Section 158.
(4) Section 161.
(5) Section 163.
(6) Section 164.
(f) Carry out the consultation functions vested in the Secretary by Executive Order 11912 (3 CFR, 1976 Comp., p. 114), as amended, relating to automobiles.
The National Highway Traffic Safety Administration consists of a headquarters organization located in Washington, DC, and a unified field organization consisting of ten geographic regions. The organization of, and general spheres of responsibility within, the NHTSA are as follows:
(a)
(1)
(i) Represents the Department and is the principal advisor to the Secretary in all matters related to chapters 301, 303, 321, 323, 325, 327, 329 and 331 of Title 49 U.S.C.; 23 U.S.C. chapter 4, except section 409; as each relates to highway safety, sections 153, 154, 158, 161, 163, 164 and 313 of Title 23 U.S.C.; and such other authorities as are delegated by the Secretary of Transportation (49 CFR sections 1.94 and 1.95);
(ii) Establishes NHTSA program policies, objectives, and priorities and directs development of action plans to accomplish the NHTSA mission;
(iii) Directs, controls, and evaluates the organization, program activities, performance of NHTSA staff, program and field offices;
(iv) Approves broad legislative, budgetary, fiscal and program proposals and plans; and
(v) Takes management actions of major significance, such as those relating to changes in basic organization pattern, appointment of key personnel, allocation of resources, and matters of special political or public interest or sensitivity.
(2)
(3) [Reserved]
(4)
(5)
(6)
(b)
(c)
(1)
(2)
(3)
(a) The Deputy Administrator is the “first assistant” to the Administrator for purposes of the Federal Vacancies Reform Act of 1998 (5 U.S.C. 3345–3349d), and shall, in the event the Administrator dies, resigns, or is otherwise unable to perform the functions and duties of the office, serve as the Acting Administrator, subject to the limitations in the Federal Vacancies Reform Act of 1998.
(b) In the event of the absence or disability of both the Administrator and the Deputy Administrator, or in the event that both positions are vacant, the following officials, in the order indicated, shall serve as Acting Deputy Administrator and shall perform the functions and duties of the Administrator, except for any non-delegable statutory and/or regulatory functions and duties:
(1) Chief Counsel;
(2) Senior Associate Administrator for Vehicle Safety;
(3) Senior Associate Administrator for Traffic Injury Control;
(4) Senior Associate Administrator for Policy and Operations.
(c) In order to qualify for the line of succession, officials must be encumbered in their position on a permanent basis.
(a) All authorities lawfully vested in the Administrator and reserved to him/her in this Regulation or in other NHTSA directives may be exercised by the Deputy Administrator and, in the absence of both Officials, by the Chief Counsel, unless specifically prohibited.
(b) In exercising the powers and performing the duties delegated by this part, officers of the NHTSA and their delegates are governed by applicable laws, executive orders, regulations, and other directives, and by policies, objectives, plans, standards, procedures, and limitations as may be issued from time to time by or on behalf of the Secretary of Transportation, the Administrator, the Deputy Administrator and the Chief Counsel or, with respect to matters under their jurisdiction, by or on behalf of the Senior Associate Administrators, Associate Administrators, Regional Administrators, and Directors of Staff Offices.
(c) Each officer to whom authority is delegated by this part may redelegate and authorize successive redelegations of that authority subject to any conditions the officer prescribes. Redelegations of authority shall be in written form and shall be published in the
(d) Each officer to whom authority is delegated will administer and perform the functions described in the officer's respective functional statements.
The authorities reserved to the Secretary of Transportation are set forth in § 1.21 of Part 1 and in Part 95 of the regulations of the Office of the Secretary of Transportation in subtitle A of this Title (49 CFR Parts 1 and 95).
The delegations of authority in this part do not extend to the following authority which is reserved to the Administrator, except when exercised pursuant to §§ 501.4 and 501.5(a):
(a) The authority under chapter 301—Motor Vehicle Safety—of Title 49 of the United States Code to:
(1) Issue, amend, or revoke final federal motor vehicle safety standards and regulations;
(2) Make final decisions concerning alleged safety-related defects and noncompliances with Federal motor vehicle safety standards;
(3) Grant or renew temporary exemptions from federal motor vehicle safety standards; and
(4) Grant or deny appeals from determinations upon petitions for inconsequential defect or noncompliance.
(b) The authority under 23 U.S.C. chapter 4, as amended, to:
(1) Apportion authorization amounts and distribute obligation limitations for State highway safety programs under 23 U.S.C. 402;
(2) Award grants to the States under the National Priority Safety Programs, 23 U.S.C. 405;
(3) Issue, amend, or revoke uniform State highway safety guidelines and rules identifying highly effective highway safety programs under 23 U.S.C. 402;
(4) Fix the rate of compensation for non-government members of agency sponsored committees which are entitled to compensation.
(c) The authority under chapters 303, 321, 323, 325, and 329 (except section 32916(b)) of Title 49 of the United States Code to:
(1) Issue, amend, or revoke final rules and regulations; and
(2) Assess civil penalties and approve manufacturer fuel economy credit plans under chapter 329.
(a)
(b) [Reserved]
(c)
(1) Act as the NHTSA Director of Equal Employment Opportunity.
(2) Act as NHTSA coordinator for matters under Title VI of the Civil Rights Act of 1964 (42 U.S.C. 2000d et seq.), Executive Order 12250 (3 CFR, 1980 Comp., p. 298), and regulations of the Department of Justice.
(d)
(1) Exercise the powers and perform the duties of the Administrator with respect to setting of odometer regulations authorized under 49 U.S.C. chapter 327, and with respect to providing technical assistance and granting extensions of time to the states under 49 U.S.C. 32705.
(2) Establish the legal sufficiency of all investigations and enforcement actions conducted under the authority of the following chapters, including notes, of Title 49 of the United States Code Chapters 301, 303, 321, 323, 325, 327, 329 and 331; to make an initial penalty demand based on a violations of any of these chapters; and to compromise any civil penalty or monetary settlement in an amount of $100,000 or less resulting from a violation of any of these chapters.
(3) Exercise the powers of the Administrator under 49 U.S.C. 30166(c), (g), (h), (i), and (k).
(4) Issue subpoenas, after notice to the Administrator, for the attendance of witnesses and production of documents pursuant to chapters 301, 321, 323, 325, 327, 329 and 331 of Title 49 of the United States Code.
(5) Issue authoritative interpretations of the statutes administered by NHTSA and the regulations issued by the agency.
(e)
(f)
(g)
Board of Governors of the Federal Reserve System.
Proposed rule.
The Board of Governors of the Federal Reserve System (Board) is inviting comments on a proposed rule to implement section 318 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which directs the Board to collect assessments, fees, or other charges equal to the total expenses the Board estimates are necessary or appropriate to carry out the supervisory and regulatory responsibilities of the Board for bank holding companies and savings and loan holding companies with total consolidated assets of $50 billion or more and nonbank financial companies designated for Board supervision by the Financial Stability Oversight Council (Council).
Comments should be received by June 15, 2013.
You may submit comments, identified by Docket No. 1457 and RIN 7100–AD–95, by any of the following methods:
•
•
•
•
•
Mark Greiner (202–452–5290), Nancy Perkins (202–973–5006), or William Spaniel (202–452–3469), Division of Banking Supervision and Regulation; Laurie Schaffer, Associate General Counsel (202–452–2272) or Michelle Moss Kidd, Attorney (202–736–5554), Legal Division; Board of Governors of the Federal Reserve System, 20th and C Streets NW., Washington, DC 20551. Users of Telecommunication Device for the Deaf (TTD) only, contact (202) 263–4869.
Section 318 of the Dodd-Frank Act directs the Board to collect assessments, fees, or other charges (assessments) from bank holding companies and savings and loan holding companies with $50 billion or more in total consolidated assets, and nonbank financial companies designated by the Council pursuant to section 113 of the Dodd-Frank Act for supervision by the Board
Under the proposal, each calendar year would be an assessment period. Companies would be covered by this rule if the total consolidated assets for the company meets or exceeds $50 billion or the company has been designated for Board supervision by the Council during the assessment period. The Board proposes to notify those companies of the amount of their assessment no later than July 15 of the year following each assessment period. After an opportunity for appeal, assessed companies would be required to pay their assessments by September 30 of the year following the assessment period. The Board is proposing to collect assessments beginning with the 2012 assessment period. The Board believes that initiating the assessment program with the 2012 assessment period is appropriate as the Board has completed the development of a framework for the estimation of appropriate expenses and the collection of assessments. Additionally, the 2012 assessment period would be the first full calendar-year assessment period subsequent to the effective date of section 318 of Dodd-Frank.
The Board is inviting comments on all aspects of this proposed rulemaking.
The Board would make the determination for each calendar-year period (the assessment period) that a company is a bank holding company or savings and loan holding company with total consolidated assets equal to or exceeding $50 billion, or a nonbank financial company designated for Board supervision by the Council, based on information reported by the company on regulatory or other reports as determined by the Board.
• A company that, on December 31 of the assessment period, is a top-tier bank holding company, other than a foreign bank holding company, as defined in section 2 of the Bank Holding Company Act,
• A company that, on December 31 of the assessment period, is a top-tier savings and loan holding company, other than a foreign savings and loan holding company, as defined in section 10 of the Home Owners' Loan Act,
• A foreign company that, on December 31 of the assessment period, is a top-tier bank holding company that has total consolidated assets of $50 billion or more as determined based on the average of the foreign banking organization's total consolidated assets reported for the assessment period on the Capital and Asset Report for Foreign Banking Organizations (FR Y–7Q) submissions;
• A foreign company that, on December 31 of the assessment period, is a savings and loan holding company that has total consolidated assets of $50 billion or more as determined based on the average of the foreign savings and loan holding company's total consolidated assets reported for the assessment period on regulatory reporting forms required for the foreign savings and loan holding company;
• A company that is a nonbank financial company designated for supervision by the Board under section 113 of the Dodd-Frank Act on December 31 of the assessment period.
The term “total assessable assets” means the amount of assets that will be used to calculate an assessed company's assessment. In order to collect assessments that reflect the Board's role as the consolidated supervisor of assessed companies, further described in Section A.4, total assessable assets would include total assets for all activities subject to the Board's supervisory authority as the consolidated supervisor. For a U.S.-domiciled assessed company, total assessable assets would be the company's total consolidated assets of its entire worldwide operations, determined by using an average of the total consolidated asset amounts reported in applicable regulatory reports for the assessment period.
For a foreign bank holding company, total assessable assets would be equal to the company's total combined assets of U.S. operations,
• A top-tier, U.S.-domiciled bank holding company or U.S.-domiciled savings and loan holding company;
• U.S. branches and agencies;
• U.S.-domiciled nonbank subsidiaries;
• Edge Act and Agreement Corporations;
For assessment periods after 2013, the Board proposes to modify the FR Y–7Q by adding a line item for reporting the total combined assets of a foreign banking organization's U.S. operations, consistent with the Board's supervisory and regulatory authority over foreign banking organizations' U.S. operations.
Under the proposed rule, each calendar year would be an assessment period. For each assessment period, the Board would make a determination as to whether an entity is an assessed company for that assessment period. The Board anticipates that the population of assessed companies will be relatively stable, and it is likely that an entity that is an assessed company during one assessment period will be an assessed company for following assessment periods. Nevertheless, some entities with average total consolidated assets near the $50 billion threshold might be included in one assessment period and not in another.
The Board would determine which companies, as of December 31 of the prior calendar year, (i) were of the types of entities enumerated in the rule (i.e., a bank holding company, savings and loan holding company, or designated nonbank financial company subject to Board supervision) and (ii) had average total consolidated assets equal to or exceeding the $50 billion threshold, as reported on the relevant reporting form(s) or based on other information as the Board may consider. The Board would notify each company that it is an assessed company by July 15 of each calendar year following the assessment period.
The assessment basis means the applicable estimated expenses
For each assessment period, the Board's assessment basis would be the Board's estimate of the total expenses necessary or appropriate to carry out the supervisory and regulatory responsibilities of the Board with respect to the population of assessed companies, based on an average of estimated expenses over the current and prior two assessment periods. For the 2012 assessment period, the Board estimates that the assessment basis would be approximately $440 million. Thereafter, to mitigate volatility in assessments and provide a more stable basis from year to year, the Board would calculate a three-year average of its estimated expenses, and would determine assessments for each year based on that three-year average. Thus, as an example, the assessment basis for 2015 would be the average of the Board's estimated expenses relating to assessed companies from calendar years 2013, 2014, and 2015. For the assessment bases for calendar years 2012, 2013, and 2014, the Board would use the estimate of its expenses for 2012, the first year for which it will collect assessments.
In general, total expenses relating to the supervision of a company are a function of the size and associated complexity of the company. For example, for companies with assets of $50 billion or more, supervision typically consists of onsite teams with a continuous presence at the firm, offsite surveillance and monitoring, and a series of targeted onsite examinations conducted throughout the year that focus on individual areas of operations and risk. Larger companies are often more complex companies, with associated risks that play a large role in determining the supervisory resources needed for that company. The largest companies, because of their increased complexity, risk and geographic footprints, usually receive more supervisory attention. For example, a number of regulations in development to implement provisions of the Dodd-Frank Act are directed at financial institutions with total consolidated assets of $50 billion or more and nonbank companies designated for supervision by the Board, and some of these regulations are tailored further based on the size of a company.
Apportioning the assessment basis based on the total consolidated asset size of the assessed companies is generally reflective of the amount of supervisory and regulatory expenses associated with a particular company, and generally is information that is well understood, objective, transparent, readily available, and comparable among all types of assessed companies. As a result, the Board proposes to determine assessments based on the assessed companies' total assessable assets for the assessment period.
The proposal would apportion the assessment basis among assessed companies by means of an assessment formula that uses the total assessable asset size of each assessed company. For each assessment period, the assessment formula applied to the assessed companies is proposed to be:
Each company's assessment would be computed using a base amount of $50,000 for each assessed company. The Board believes that including this base amount in each assessment is appropriate to ensure that the nominal expenses related to the Board's supervision and regulation of such companies, particularly for those companies that are near the $50 billion threshold, are covered. The “assessment rate” would be determined each assessment period according to this formula:
Over the first three years of the program, the assessment rate would be fixed. After the Board determines the assessment rate for 2012, it would use that assessment rate for calculating the assessment for the following two assessment periods, ending with the assessments for 2014. Thereafter, for each assessment period, the Board would calculate an assessment rate by averaging the Board's relevant expenses for the past three years. Keeping the same assessment rate for the first three years and the subsequent three-year average would reduce year-to-year fluctuations in assessments.
For purposes of illustration, using the methodologies set forth in this proposal and based on information as of the date of this notice of proposed rulemaking, the Board estimates that for 2012 there would be approximately 70 assessed companies with aggregate total assessable assets of about $20 trillion and that the assessment basis would be about $440 million. Using these figures, a company with total assessable assets of $50 billion
Under the proposal, the Board would send a notice of assessment to each assessed company no later than July 15 of the year following the assessment period stating that the Board had determined the company to be an assessed company for the prior calendar year, stating the amount of the company's total assessable assets and the amount the assessed company must pay by September 30. The Board would also, no later than July 15, publish on its Web site the assessment formula for that assessment period. For the 2012 assessment period, the notice of assessment and the date on which the assessment is due may be adjusted depending on the date of the issuance of the final regulation.
Companies identified as assessed companies would have 30 calendar days from July 15 to appeal the Board's determination of the company as an assessed company or the Board's determination of the company's total assessable assets. Under the proposal, companies choosing to appeal must submit a request for redetermination in writing and include all the pertinent facts the company believes would be relevant for the Board to consider. Grounds for appeal would be limited to (i) whether the assessed company was not properly considered an assessed company (i.e., it is not a bank holding company, savings and loan holding company, or nonbank financial company designated by the Council as of December 31 of the assessment period), or (ii) review of the Board's determination of the assessed company's total assessable assets. The Board would consider the company's request and respond within 15 calendar days from the end of the appeal period with the results of its review of any properly filed appeal. A successful appeal would not change the assessment for any other company.
Under the proposal, each assessed company would pay its assessments using the Fedwire Funds Service (Fedwire) to the Federal Reserve Bank of Richmond. The assessments will then be transferred to the U.S. Treasury's General Account. Assessments must be credited to the Board by September 30 of the year following the assessment period.
The FR Y–7Q requires each top-tier foreign banking organization to file asset and capital information. Currently, Part 1 of the report requires the filing of capital and asset information for the top-tier foreign banking organization,
For the purpose of determining a foreign assessed company's total assessable assets, the Board believes that combining the assets of the foreign assessed company's U.S. branches and agencies with the total assets of all U.S. domiciled affiliates reported on other regulatory reports on a standalone basis would likely not yield a result that is comparable to the consolidated approach required of U.S.-domiciled assessed companies, which report total consolidated assets on Schedule HC of FR Y–9C according to standard rules of consolidation. That is, not all standalone reports itemize separately the intercompany balances and transactions between only U.S. affiliates that would be netted out on a U.S. consolidated basis. Therefore, in order to improve parity among all assessed companies with respect to the determination of total assessable assets, the Board is proposing to revise Part 1 of the FR Y–7Q to collect the top-tier foreign banking organization's total combined assets of U.S. operations,
In addition, the Board is proposing to revise Part 1 of the FR Y–7Q to collect information about certain foreign banking organizations more frequently. As mentioned above, only top-tier foreign banking organizations with financial holding company status file Part 1 of the FR Y–7Q quarterly, while a top-tier foreign banking organization would report annually if the foreign banking organization, or any foreign banking organization in its tiered structure, has not effectively elected to be a financial holding company. Accordingly, for purposes of determining whether a foreign banking organization is an assessed company and the amount of a foreign assessed company's total assessable assets more frequent than annually, the Board is proposing to revise the FR Y–7Q quarterly reporting requirements for Part 1 to include all top-tier foreign banking organizations, regardless of financial holding company designation, with total consolidated worldwide assets of $50 billion or more as reported on Part 1 of the FR Y–7Q. Once a foreign banking organization has total consolidated assets of $50 billion or more and begins to report quarterly, the foreign banking organization must continue to report Part 1 quarterly unless and until the foreign banking organization has reported total consolidated assets of less than $50 billion for each of all four quarters in a full calendar year. Thereafter, the foreign banking organization may revert to annual reporting, in accordance with the FR Y–7Q reporting form's instructions for annual reporting of Part 1. If at any time, after reverting to annual reporting, a foreign banking organization has total consolidated assets of $50 billion or more, the FBO must return to quarterly reporting of Part 1. Regardless of size, all top-tier foreign banking organizations that have elected to be financial holding companies at the foreign banking organization's top tier or tiered structure would continue to report quarterly.
Section 722 of the Gramm-Leach-Bliley Act (Pub. L. 106–102, 113 Stat. 1338, 1471, 12 U.S.C. 4809) requires the Federal banking agencies to use plain language in all proposed and final rules published after January 1, 2000. The Board invites comment on how to make the proposed rule easier to understand. For example:
• Is the material organized to suit your needs? If not, how could the Board present the rule more clearly?
• Are the requirements in the rule clearly stated? If not, how could the rule be more clearly stated?
• Do the regulations contain technical language or jargon that is not clear? If so, which language requires clarification?
• Would a different format (grouping and order of sections, use of headings, paragraphing) make the regulation easier to understand? If so, what changes would achieve that?
• Is this section format adequate? If not, which of the sections should be changed and how?
• What other changes can the agencies incorporate to make the regulation easier to understand?
In accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506; 5 CFR 1320 Appendix A.1), the Board reviewed the proposed rule under the authority delegated to the Board by Office of Management and Budget (OMB). The Board may not conduct or sponsor, and a respondent is not required to respond to, an information collection unless it displays a currently valid OMB control number.
The proposed rule contains requirements subject to the PRA. The reporting requirements are found in sections 246.3(e)(3) and 246.5(b).
Section 318 of the Dodd-Frank Act directs the Board to collect assessments, fees, or other charges, from assessed companies equal to the expenses the Board estimates would be necessary and appropriate to carry out its supervision and regulation of those companies. Section 318 describes these companies as (1) a bank holding company (BHC) (other than a foreign bank holding company) with total consolidated assets of $50 billion or more determined based on the average of the BHC's total consolidated assets reported during the assessment period on its Schedule HC—Consolidated Balance Sheet of the BHC's Consolidated Financial Statements for Bank Holding Companies (FR Y–9C) (OMB No. 7100–0128) forms; (2) a savings and loan holding company (SLHC) (other than a foreign savings and loan holding company) with total consolidated assets of $50 billion or more, (3) a foreign company that is a BHC or SLHC with $50 billion or more in total consolidated assets determined based on the average of the foreign company's total consolidated assets reported during the assessment period on the Capital and Asset Report for Foreign Banking Organizations (FR Y–7Q; OMB No. 7100–0125) and (4) a nonbank financial company designated for supervision by the Board under section 113 of the Dodd-Frank Act. In
Under section 246.5(b) upon the Federal Reserve issuing the notice of assessment to each assessed company, the company would have 30 calendar days to submit a written statement to appeal the Board's determination of the company as (i) a BHC, SLHC, foreign bank holding company, or nonbank financial company supervised by the Board; (ii) the Board's determination of the company's total consolidated assets, or (iii) the Board's determination of the company's total assessable assets, as set forth in 246.4(e) of this rule. This new collection would be titled the Dodd-Frank Act Assessment Fees Request for Redetermination (FR 4030; OMB No. 7100—to be assigned).
The Board estimates that 7 assessed companies would submit a written request for appeal annually. The Board estimates that these assessed companies would take, on average, 40 hours (one business week) to write and submit the written request. The total annual PRA burden for the new FR 4030 information collection is estimated to be 280 hours.
Comments are invited on: (1) Whether the proposed collection of information is necessary for the proper performance of the Board's functions, including whether the information has practical utility; (2) the accuracy of the Board's estimate of the burden of the proposed information collection, including the cost of compliance; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of information collection on respondents, including through the use of automated collection techniques or other forms of information technology. Comments on the collection of information should be sent to Cynthia Ayouch, Federal Reserve Board Clearance Officer, Division of Research and Statistics, Mail Stop 95–A, Board of Governors of the Federal Reserve System, Washington, DC 20551. Copies of such comments may also be submitted to the Office of Management and Budget, 725 17th St. NW., #10235 (Docket FRB Docket No. R–1457), Washington, DC 20503, Attn: Federal Reserve Desk Officer.
In accordance with Section 3(a) of the Regulatory Flexibility Act, 5 U.S.C. 601
Based on its analysis and for the reasons stated below, the Board believes that this proposed rule would not have a significant economic impact on a substantial number of small entities. A final regulatory flexibility analysis will be conducted after consideration of comments received during the public comment period if the Board determines that the rule will have a significant economic impact on a substantial number of small entities.
1.
2.
3.
4.
5.
Administrative practice and procedure, Assessments, Banks, Banking, Holding companies, Nonbank financial companies, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, the Board proposes to amend 12 CFR chapter II as follows:
Pub. L. 111–203, 124 Stat. 1376, 1526, and section 11(s) of the Federal Reserve Act (12 U.S.C. 248(s)).
(a)
(b)
(1) Any bank holding company having total consolidated assets of $50 billion or more, as defined below;
(2) Any savings and loan holding company having total consolidated assets of $50 billion or more, as defined below; and
(3) Any nonbank financial company supervised by the Board, as defined below.
(c)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(a)
(1) is a top-tier company that, on December 31 of the assessment period:
(i) is a bank holding company, other than a foreign bank holding company, with $50 billion or more in total consolidated assets, as determined based on the average of the bank holding company's total consolidated assets reported for the assessment period on the Federal Reserve's Form FR Y–9C (“FR Y–9C”),
(ii) is a savings and loan holding company, other than a foreign savings and loan holding company, with $50 billion or more in total consolidated assets, as determined based on the average of the savings and loan holding company's total consolidated assets as reported for the assessment period on the FR Y–9C or on column B of the Quarterly Savings and Loan Holding Company Report (FR 2320), as applicable,
(2) is a top-tier foreign bank holding company on December 31 of the assessment period, with $50 billion or more in total consolidated assets, as determined based on the average of the foreign bank holding company's total consolidated assets reported for the assessment period on the Federal Reserve's Form FR Y–7Q (“FR Y–7Q”),
(3) is a top-tier foreign savings and loan holding company on December 31 of the assessment period, with $50 billion or more in total consolidated assets, as determined based on the average of the foreign savings and loan holding company's total consolidated assets reported for the assessment period on the reporting forms applicable during the assessment period, or
(4) the Council has determined under section 113 of the Dodd-Frank Act (12 U.S.C. § 5323) to be supervised by the Board and for which such determination is in effect as of December 31 of the assessment period.
(b)
(a)
(b)
(c)
(1) The assessment rate will be calculated according to this formula:
(2) For the calculation set forth in (1), above, the number of assessed companies and the total assessable assets of all assessed companies will each be that of the relevant assessment period, provided, however, that for the assessment periods corresponding to 2012, 2013 and 2014, the Board shall use the number of assessed companies and the total assessable assets of the 2012 assessment period to calculate the assessment rate.
(d)
(1) For the 2012, 2013, and 2014 assessment periods, the assessment basis is the amount of total expenses the Board estimates is necessary or appropriate to carry out the supervisory and regulatory responsibilities of the Board with respect to assessed companies for 2012.
(2) For the 2015 assessment period and for each assessment period thereafter, the assessment basis is the average of the amount of total expenses the Board estimates is necessary or appropriate to carry out the supervisory and regulatory responsibilities of the Board with respect to assessed companies for that assessment period and the two prior assessment periods.
(e)
(1)
(2)
(i)
(ii)
(A) Top-tier, U.S.-domiciled bank holding companies and savings and loan holding companies,
(B) Related branches and agencies in the United States (line items 1.i, column A, on Schedule RAL of Report of Assets and Liabilities of U.S. Branches and Agencies of Foreign Banks (FFIEC 002) plus due from related institutions in foreign countries (line items 2.a, 2.b(1), 2.b(2), and 2.c from column A, part 1 on Schedule M), as reported on FFIEC 002, provided however that due from head office of parent bank (line item 2.a, column A, part 1 on Schedule M of FFIEC 002) would be included net of due to head office of parent bank (line item 2.a, column B, part 1 on Schedule M of FFIEC 002) when there is a net due from position reported for line item 2.a., while a net due to position for line item 2.a would result in no addition to total assets with respect to line item 2.a, part 1 on Schedule M of FFIEC 002.
(C) U.S.-domiciled nonbank subsidiaries:
(D) For Edge Act and agreement corporations that are not reflected in the assets of a U.S.-domiciled parent's regulatory reporting form submission, claims on nonrelated organizations (line item 9, “consolidated total” column on Schedule RC of the Consolidated Report of Condition and Income for Edge and Agreement Corporations (FR 2886b)), plus claims on related organizations domiciled outside the United States (line items 2.a and 2.b, column A on Schedule RC–M), as reported on FR 2886b.
(E) For banks and savings associations that are not reflected in the assets of a U.S.-domiciled parent's regulatory reporting form submission, total assets (line item 12) as reported on Schedule RC—Balance Sheet of the Consolidated Reports of Condition and Income for a Bank with Domestic and Foreign Offices (FFIEC 031), or total assets (line item 12) as reported on Schedule RC—Balance Sheet of the Consolidated Reports of Condition and Income for a Bank with Domestic Offices Only (FFIEC 041), as applicable.
(F) For broker-dealers that are not reflected in the assets of a U.S.-domiciled parent's regulatory reporting form submission, total assets (line item 16, “total” column) as reported on statement of financial condition of the Securities and Exchange Commission's Form X–17A–5 (FOCUS REPORT), Part II, Part IIa, or Part II CSE, as applicable.
(4)
(5)
(a)
(b)
(1) Each assessed company will have thirty calendar days from July 15 to submit a written statement to appeal the Board's determination (i) that the company is an assessed company; or (ii) of the company's total assessable assets.
(2) The Board will respond with the results of its consideration to an assessed company that has submitted a written appeal within 15 calendar days from the end of the appeal period.
(a)
(b)
(1) If the Board does not receive the total amount of an assessed company's assessment by the collection date for any reason not attributable to the Board, the assessment will be delinquent and the assessed company shall pay to the Board interest on any sum owed to the Board according to this rule (delinquent payments).
(2) Interest on delinquent payments will be assessed beginning on the first calendar day after the collection date, and on each calendar day thereafter up to and including the day payment is received. Interest will be simple interest, calculated for each day payment is delinquent by multiplying the daily equivalent of the applicable interest rate by the amount delinquent. The rate of interest will be the United State Treasury Department's current value of funds rate (the “CVFR percentage”); issued under the Treasury Fiscal Requirements Manual and published quarterly in the
Bureau of Consumer Financial Protection.
Proposed rule with request for public comment.
This rule proposes clarifying and technical amendments to a final rule issued by the Bureau of Consumer Financial Protection (Bureau) on January 10, 2013, which, among other things, lengthens the time for which a mandatory escrow account established for a higher-priced mortgage loan (HPML) must be maintained. The rule also established an exemption from the escrow requirement for certain creditors that operate predominantly in “rural” or “underserved” areas. The amendments clarify the determination method for the “rural” and “underserved” designations and keep in place certain existing protections for HPMLs until other similar provisions take effect in January 2014.
Comments must be received on or before May 3, 2013.
You may submit comments, identified by Docket No. CFPB–2013–0009 or RIN 3170–AA37, by any of the following methods:
•
•
All comments, including attachments and other supporting materials, will become part of the public record and subject to public disclosure. Sensitive personal information, such as account numbers or social security numbers, should not be included. Comments will not be edited to remove any identifying or contact information.
Whitney Patross, Attorney; Joseph Devlin and Richard Arculin, Counsels; Office of Regulations, at (202) 435–7700.
In January 2013, the Bureau issued several final rules concerning mortgage markets in the United States pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) Public Law 111–203, 124 Stat. 1376 (2010) (2013 Title XIV Final Rules). One of these rules was Escrow Requirements Under the Truth in Lending Act (Regulation Z) (2013 Escrows Final Rule),
The Bureau is now proposing certain clarifying and technical amendments to the 2013 Escrows Final Rule, including clarification of how to determine whether a county is considered “rural” or “underserved” for the application of the escrows requirement and the other Dodd-Frank Act regulations.
In addition, the proposal would restore certain existing Regulation Z requirements related to the consumer's ability to repay and prepayment penalties for HPMLs. The scope of these protections is being expanded in connection with the 2013 Title XIV Final Rules to apply to most mortgage transactions, rather than just HPMLs. For this reason, the 2013 Escrows Final Rule removed the regulatory text providing these protections solely to HPMLs. That final rule, however, takes effect on June 1, 2013, whereas the new ability-to-repay and prepayment penalty provisions do not take effect until January 10, 2014. To prevent any interruption in applicable protections, this proposal would establish a temporary provision to ensure the protections remain in place for HPMLs until the expanded provisions take effect in January 2014.
In addition, the Bureau is making some technical corrections to enhance clarity.
In response to an unprecedented cycle of expansion and contraction in the mortgage market that sparked the most severe U.S. recession since the Great Depression, Congress passed the Dodd-Frank Act, which was signed into law on July 21, 2010. In the Dodd-Frank Act, Congress established the Bureau and, under sections 1061 and 1100A, generally consolidated the rulemaking authority for Federal consumer financial laws, including the Truth in Lending Act (TILA), in the Bureau.
On February 13, 2013, the Bureau announced an initiative to support implementation of the new mortgage rules (Implementation Plan),
This proposed rule is the first publication of additional guidance and updates regarding the 2013 Title XIV Final Rules. Priority for this first set of updates has been given to the 2013 Escrows Final Rule because the effective date is June 1, 2013, and certainty regarding compliance is a matter of some urgency. Another update to certain of the 2013 Title XIV Final Rules will be proposed shortly, which will affect provisions that take effect in January 2014, and others will be issued as needed.
The Bureau is issuing this proposed rule pursuant to its authority under TILA and the Dodd-Frank Act. Section 1061 of the Dodd-Frank Act transferred to the Bureau the “consumer financial protection functions” previously vested in certain other Federal agencies, including the Federal Reserve Board (Board) and the Department of Housing and Urban Development (HUD). The term “consumer financial protection function” is defined to include “all authority to prescribe rules or issue orders or guidelines pursuant to any Federal consumer financial law, including performing appropriate functions to promulgate and review such rules, orders, and guidelines.”
The Bureau is proposing to amend the 2013 Escrows Final Rule.
The Bureau is making a technical correction to 1026.35(b)(1) to update a citation.
Four of the Bureau's January 2013 mortgage rules included provisions that provide for special treatment under various Regulation Z requirements for certain credit transactions made by creditors operating predominantly in “rural” or “underserved” areas: (1) § 1026.35(b)(2)(iii) provides an exemption to the 2013 Escrows Final Rule's escrow requirement for HPMLs; (2) § 1026.43(f) provides an allowance to originate balloon-payment qualified mortgages under the 2013 ATR Final Rule; (3) § 1026.32(d)(1)(ii)(C) provides an exemption from the balloon payment prohibition on high-cost mortgages under the 2013 HOEPA Final Rule; and (4) § 1026.35(c)(4)(vii)(H) provides an exemption from a requirement to obtain a second appraisal for certain HPMLs under the 2013 Interagency Appraisals Final Rule. These provisions rely on the criteria for “rural” and/or “underserved” counties set forth in § 1026.35(b)(2)(iv)(A) and (B), respectively, of the 2013 Escrows Final Rule, which takes effect on June 1, 2013.
Two special provisions for creditors operating predominantly in “rural” or “underserved” areas were set forth in the Dodd-Frank Act amendments to TILA, but the terms were not defined by statute. TILA section 129D, as added and amended by Dodd-Frank Act sections 1461 and 1462 and implemented by § 1026.35(b), generally requires that creditors establish escrow accounts for HPMLs secured by a first lien on a consumer's principal dwelling, but the statute also authorizes the Bureau to exempt from this requirement transactions by a creditor that, among other criteria, “operates predominantly in rural or underserved areas.” TILA section 129D(c)(1). Similarly, the ability-to-repay provisions in Dodd-Frank Act section 1412 contain a set of criteria with regard to certain balloon-payment mortgages originated and held in portfolio by certain creditors that operate predominantly in rural or underserved areas, allowing those loans to be considered qualified mortgages.
Through the 2013 Escrows Final Rule, the Bureau adopted § 1026.35(b)(2)(iv)(A) and (B) to define “rural” and “underserved” respectively for the purposes of the four rules discussed above that contain special provisions that use one or both of those terms. The 2013 Escrows Final Rule also provided comment 35(b)(2)(iv)–1 to clarify further the criteria for “rural” and “underserved” counties, and provided that the Bureau will annually update on its public Web site a list of counties that meet the definitions of rural and underserved in § 1026.35(b)(2)(iv). In advance of the rule's June 1 effective date, the Bureau is proposing to amend § 1026.35(b)(2)(iv) and comment 35(b)(2)(iv)–1 to clarify how to determine whether a county is rural or underserved for the purposes of these provisions.
The Bureau is proposing modifications to § 1026.35(b)(2)(iii) and comment 35(b)(2)(iii)–1.i for clarification purposes and for consistency with other provisions. As adopted, § 1026.35(b)(2)(iii) and its commentary state that the Bureau will designate or determine which counties are rural or underserved for the purposes of the special provisions of the four rules discussed above. This was not the Bureau's intent. Rather, the Bureau intended to require determinations of “rural” or “underserved” status to be made by creditors as prescribed by § 1026.35(b)(2)(iv)(A) and (B), but also intended for the Bureau to apply both tests to each U.S. county and publish an annual list of counties that satisfy either test for a given calendar year, which creditors may rely upon as a safe harbor. The Bureau is proposing modifications to § 1026.35(b)(2)(iii)(A) and comment 35(b)(2)(iii)–1.i for the purposes of clarification and consistency with these provisions.
As adopted, § 1026.35(b)(2)(iv)(A) defines “rural” based on currently applicable UICs established by the USDA–ERS. The UICs are based on the definitions of “metropolitan statistical area” and “micropolitan statistical area” as developed by the Office of Management and Budget (OMB), along with other factors reviewed by the ERS that place counties into twelve separately defined UICs depending, in part, on the size of the largest city and town in the county. Based on these definitions, § 1026.35(b)(2)(iv)(A) as adopted states that a county is “rural” during a calendar year if it is neither in a metropolitan statistical area nor in a micropolitan statistical area that is adjacent to a metropolitan statistical area, as those terms are defined by OMB and applied under currently applicable UICs.
As adopted, comment 35(b)(2)(iv)–1.i explains that, for the purposes of the provision, the terms “metropolitan statistical areas” and “micropolitan statistical areas adjacent to a metropolitan statistical area” are given the same meanings used by USDA–ERS for the purposes of determining UICs. The USDA–ERS considers micropolitan counties as “adjacent” to a metropolitan statistical area for this purpose if they abut a metropolitan statistical area and have at least 2% of employed persons commuting to work in the core of the metropolitan statistical area.
Nevertheless, the Bureau believes additional commentary that explains the meaning of “adjacent” more directly would be useful to facilitate compliance with § 1026.35(b)(2)(iv) and the provisions that rely on it. Accordingly, the Bureau is proposing to amend comment 35(b)(2)(iv)–1.i. to state expressly that “adjacent” entails physical contiguity with a metropolitan statistical area where certain minimum commuting standards are also met, as defined by the USDA–ERS. The Bureau believes this is consistent with USDA–ERS's use of “adjacent” and better explains the rule for compliance purposes.
Similarly, the Bureau is proposing language to specify under § 1026.35(b)(2)(iv)(A) how “rural” status
The Bureau is also proposing comment 35(b)(2)(iv)–2.i to provide an example of how “rural” status is determined. In addition, the Bureau is making small technical changes to the rule provision and commentary to enhance clarity.
Section 1026.35(b)(2)(iii)(A) creates an exemption from the HPML escrow requirement for transactions by creditors operating in rural or underserved counties, if they meet certain criteria involving the loans they originated
As adopted by the 2013 Escrows Final Rule, § 1026.35(b)(2)(iv)(B) states that a county is “underserved” during a calendar year if, “according to Home Mortgage Disclosure Act (HMDA) data for that year,” no more than two creditors extended covered transactions, as defined in § 1026.43(b)(1), secured by a first lien, five or more times in the county. However, HMDA data typically are released for a given calendar year during the third or fourth quarter of each subsequent calendar year. It is thus not generally possible for creditors to make determinations concerning whether a county was underserved during the preceding calendar year based on that preceding year's HMDA data, because such data likely will not be available until late in the following year. In wording § 1026.35(b)(2)(iv)(B) as it did, the Bureau did not intend to require the use of HMDA data that is not yet available at the time the determination of a county's “underserved” status is made; the Bureau's intent was to provide for the use of the most recent HMDA data available at the time of the determination.
The Bureau therefore is proposing to amend § 1026.35(b)(2)(iv)(B) to clarify that a county is considered “underserved” during a given calendar year based on HMDA data for “the preceding calendar year” as opposed to “that calendar year.” This look-back feature coordinates with the look-back feature in the exemption itself at § 1026.35(b)(2)(iii)(A), so that a creditor would rely on the underserved status of a county based on HMDA data from two years previous to the use of the exemption, which are the most recent data available for use as the Bureau intended. The Bureau is also proposing to amend comment 35(b)(2)(iv)–1.ii to conform to this change, and to add proposed comment 35(b)(2)(iv)–2.ii to provide an example.
The Bureau is proposing language in § 1026.35(e) to keep in place existing requirements contained in § 1026.35(b) concerning assessment of consumers' ability to repay an HPML and limitations on prepayment penalties for HPMLs. These provisions were originally adopted by the Board in 2008,
The 2013 Escrows Final Rule inadvertently removed the existing language of § 1026.35(b) between June 1, 2013 and the January 10, 2014, effective date for the ability-to-repay and prepayment penalty provisions in § 1026.43. This proposed rule would restore this language at § 1026.35(e) and keep it in effect during that intervening period. The Bureau is also proposing to update existing cross-references to the § 1026.35(b) HPML provisions.
The Bureau contemplates making the proposed § 1026.35(e) effective from June 1, 2013, through and including January 9, 2014, and making the other proposed amendments effective on June 1, 2013. Section 553(d) of the Administrative Procedure Act generally requires the effective date of a final rule to be at least 30 days after publication of a rule, except for (1) a substantive rule which grants or recognizes an exemption or relieves a restriction; (2) interpretive rules and statements of policy; or (3) as otherwise provided by the agency for good cause found and published with the rule. 5 U.S.C. 553(d). The Bureau believes the proposed amendments would likely fall under one or more of these exceptions to section 553(d). The Bureau particularly notes that making the proposed amendments effective on June 1, 2013, would ease compliance and reduce disruption in the market, and ensure that the protections of the rule are uninterrupted.
The Bureau is considering the potential benefits, costs, and impacts of the proposed rule.
The proposal would clarify how to determine whether a county is considered “rural” or “underserved” for the application of the special provisions adopted in certain of the 2013 Title XIV Final Rules.
Other provisions of the proposed rule are related to underwriting and features of HPMLs. As described above, existing
Compared to the baseline established by the issuance of the final rules issued in January 2013, the proposed rule would offer consumers who obtain HPMLs from June 1, 2013 through and including January 9, 2014 the benefit of the existing protections under Regulation Z regarding ability-to-repay and prepayment penalties.
Compared to the same baseline, covered persons issuing such mortgages during this time period would incur any costs related to the ability-to-pay requirements and the restrictions on certain prepayment penalties. These costs would include the costs of documenting and verifying the consumer's ability to repay and some expected litigation-related costs. As noted above, the evidence to date is that these costs are quite limited. The 2013 ATR Final Rule and the Board's earlier 2008 HOEPA Final Rule (73 FR 44522 (July 30, 2008)) discuss these costs and benefits in greater detail. This rule simply extends these impacts from June 1, 2013 through and including January 9, 2014. The Bureau also believes that the proposed rule would benefit both consumers and covered persons in limiting unnecessary and possibly disruptive changes in the regulatory regime.
The proposed rule may have a small differential impact on depository institutions and credit unions with $10 billion or less in total assets as described in Section 1026. To the extent that HPMLs comprise a larger percentage of originations at these institutions, the relative increase in costs may be higher relative to other lenders.
The proposed rule would have some differential impacts on consumers in rural areas. In these areas, a greater fraction of loans are HPMLs. As such, to the extent that these added protections lead to additional lender costs, interest rates may be slightly higher on average; however, rural consumers will derive greater benefit from the proposed provisions than non-rural consumers.
Given the small changes for the proposed rule, the Bureau does not believe that the proposed rule would meaningfully reduce consumers' access to credit.
The Regulatory Flexibility Act (RFA) generally requires an agency to conduct an initial regulatory flexibility analysis (IRFA) and a final regulatory flexibility analysis (FRFA) of any rule subject to notice-and-comment rulemaking requirements.
This rulemaking is part of a series of rules that have revised and expanded the regulatory requirements for entities that offer HPMLs. In January 2013, the Bureau adopted the 2013 Escrows Final Rule and 2013 ATR Final Rule, along with other related rules mentioned above. Section VIII of the supplementary information to each of these rules set forth the Bureau's analyses and determinations under the RFA with respect to those rules. See 78 FR 4749, 78 FR 6575. The Bureau also notes because the potential interruption in applicable protections created by the issuance of the final rules in January was inadvertent, its Regulatory Flexibility analyses considered the impact of the protections at issue in this rule remaining in place for HPMLs until the expanded provisions take effect in January 2014. Because these rules qualify as “a series of closely related rules,” for purposes of the RFA, the Bureau relies on those analyses and determines that it has met or exceeded the IRFA requirement.
In the alternative, the Bureau also concludes that the proposed rule would not have a significant impact on a substantial number of small entities. The proposal would establish a temporary provision to ensure the protections remain in place for HPMLs until the expanded provisions take effect in January 2014. Since the new requirements and liabilities that will take effect in January 2014 as applied to higher-priced mortgage loans are very similar in nature to those that exist under the pre-existing regulations, the gap absent the proposed correction would be short-lived and would affect only the higher-priced mortgage loan market. It is therefore very unlikely absent the proposed correction that covered persons would alter their behavior substantially in the intervening period.
The proposal would also clarify how to determine whether a county is considered “rural” or “underserved” for the application of the special provisions adopted in certain of the 2013 Title XIV
As such, the Bureau affirms that the proposal would not have a significant impact on a substantial number of small entities.
This proposed rule would amend 12 CFR part 1026 (Regulation Z), which implements the Truth in Lending Act (TILA). Regulation Z currently contains collections of information approved by OMB. The Bureau's OMB control number for Regulation Z is 3170–0015. However, the Bureau has determined that this proposed rule would not materially alter these collections of information nor impose any new recordkeeping, reporting, or disclosure requirements on the public that would constitute collections of information requiring approval under the Paperwork Reduction Act, 44 U.S.C. 3501
Comments on this determination may be submitted to the Bureau as instructed in the
Advertising, Consumer protection, Mortgages, Recordkeeping requirements, Reporting, Truth in lending.
For the reasons set forth in the preamble, the Bureau proposes to further amend Regulation Z, 12 CFR part 1026, as amended by the final rule published on January 22, 2013, 78 FR 4726, as set forth below:
12 U.S.C. 2601; 2603–2605, 2607, 2609, 2617, 5511, 5512, 5532, 5581; 15 U.S.C. 1601
(a) * * *
(3) * * *
(ii) For purposes of this paragraph (a)(3), the term “material disclosures” means the required disclosures of the annual percentage rate, the finance charge, the amount financed, the total of payments, the payment schedule, and the disclosures and limitations referred to in §§ 1026.32(c) and (d) and 1026.35(e)(2).
(a) * * *
(4) * * *
(i)
(b) * * * For purposes of this paragraph (b), the term “escrow account” has the same meaning as under Regulation X (12 CFR 1024.17(b)), as amended.
(2)
(iii) Except as provided in paragraph (b)(2)(v) of this section, an escrow account need not be established for a transaction if, at the time of consummation:
(A) During the preceding calendar year, the creditor extended more than 50 percent of its total covered transactions, as defined by § 1026.43(b)(1), secured by a first lien, on properties that are located in counties that are either “rural” or “underserved,” as set forth in paragraph (b)(2)(iv) of this section;
(iv) For purposes of paragraph (b)(2)(iii)(A) of this section:
(A) A county is “rural” during a calendar year if it is neither in a metropolitan statistical area nor in a micropolitan statistical area that is adjacent to a metropolitan statistical area, as those terms are defined by the U.S. Office of Management and Budget and as they are applied under currently applicable Urban Influence Codes (UICs), established by the United States Department of Agriculture's Economic Research Service (USDA–ERS). A creditor may rely as a safe harbor on the list of counties published by the Bureau to determine whether a county qualifies as “rural” for a particular calendar year.
(B) A county is “underserved” during a calendar year if, according to Home Mortgage Disclosure Act (HMDA) data for the preceding calendar year, no more than two creditors extended covered transactions, as defined in § 1026.43(b)(1), secured by a first lien, five or more times in the county. A creditor may rely as a safe harbor on the list of counties published by the Bureau to determine whether a county qualifies as “underserved” for a particular calendar year.
(e)
(1)
(2)
(i) The penalty is otherwise permitted by law, including § 1026.32(d)(7) if the loan is a mortgage transaction described in § 1026.32(a); and
(ii) Under the terms of the loan:
(A) The penalty will not apply after the two-year period following consummation;
(B) The penalty will not apply if the source of the prepayment funds is a refinancing by the creditor or an affiliate of the creditor; and
(C) The amount of the periodic payment of principal or interest or both may not change during the four-year period following consummation.
(3)
1.
1.
1.
1.
i. During the preceding calendar year, more than 50 percent of the creditor's total first-lien covered transactions, as defined in § 1026.43(b)(1), are secured by properties located in counties that are either “rural” or “underserved,” as set forth in § 1026.35(b)(2)(iv). Pursuant to that section, a creditor may rely as a safe harbor on a list of counties published by the Bureau to determine whether counties in the United States are rural or underserved for a particular calendar year. Thus, for example, if a creditor originated 90 covered transactions, as defined by § 1026.43(b)(1), secured by a first lien, during 2013, the creditor meets this condition for an exemption in 2014 if at least 46 of those transactions are secured by first liens on properties that are located in such counties.
1.
i. Under § 1026.35(b)(2)(iv)(A), a county is rural during a calendar year if it is neither in a metropolitan statistical area nor in a micropolitan statistical area that is adjacent to a metropolitan statistical area. These areas are defined by the Office of Management and Budget and applied under currently applicable Urban Influence Codes (UICs), established by the United States Department of Agriculture's Economic Research Service (USDA–ERS). Accordingly, for purposes of § 1026.35(b)(2)(iv)(A), “adjacent” has the meaning applied by the USDA–ERS in determining a county's UIC; as so applied, “adjacent” entails a county not only being physically contiguous with a metropolitan statistical area but also meeting certain minimum population commuting patterns. Specifically, a county is “rural” if the USDA–ERS categorizes the county under UIC 4, 6, 7, 8, 9, 10, 11, or 12. Descriptions of UICs are available on the USDA–ERS Web site at
ii. Under § 1026.35(b)(2)(iv)(B), a county is underserved during a calendar year if, according to Home Mortgage Disclosure Act (HMDA) data for the preceding calendar year, no more than two creditors extended covered transactions, as defined in § 1026.43(b)(1), secured by a first lien, five or more times in the county. Specifically, a county is “underserved” if, in the applicable calendar year's public HMDA aggregate dataset, no more than two creditors have reported five or more first-lien covered transactions with HMDA geocoding that places the properties in that county. For purposes of this determination, because only covered transactions are counted,
2.
ii. A county is considered “underserved” for a given calendar year based on the most recent available HMDA data. For example, assume a creditor makes first-lien covered transactions in County Y during calendar year 2013, and the most recent HMDA data is for calendar year 2012, published in the third quarter of 2013. To determine “underserved” status for County Y in calendar year 2013 for the purposes of qualifying for the “rural or underserved” exemption in calendar year 2014, the creditor will use the 2012 HMDA data.
1.
2.
i. Initial payments for a variable-rate transaction consummated on January 1, 2010, are $1,000 per month and the loan agreement permits negative amortization to occur. Under the loan agreement, the first date that a scheduled payment in a different amount may be due is January 1, 2014, and the creditor does not have the right to change scheduled payments prior to that date even if negative amortization occurs. A prepayment penalty is permitted with this mortgage transaction provided that the other § 1026.35(e)(2) conditions are met, that is: provided that the prepayment penalty is permitted by other applicable law, the penalty expires on or before December 31, 2011, and the penalty will not apply if the source of the prepayment funds is a refinancing by the creditor or its affiliate.
ii. Initial payments for a variable-rate transaction consummated on January 1, 2010 are $1,000 per month and the loan agreement permits negative amortization to occur. Under the loan agreement, the first date that a scheduled payment in a different amount may be due is January 1, 2014, but the creditor has the right to change scheduled payments prior to that date if negative amortization occurs. A prepayment penalty is prohibited with this mortgage transaction because the payment may change within the four-year period following consummation.
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.
Proposed rule.
This proposed rule would streamline the FHA financial statement reporting requirements for lenders and mortgagees who are supervised by federal banking agencies and whose consolidated assets do not meet the thresholds set by their supervising federal banking agencies for submission of audited financial statements (currently set at $500 million in consolidated assets). HUD's regulations currently require all supervised lenders and mortgagees to submit annual audited financial statements as a condition of FHA lender approval and recertification. Through this proposed rule, in lieu of the annual audited financial statements, small supervised lenders and mortgagees would be required to submit the unaudited financial regulatory reports that align with their fiscal year ends and are required to be submitted to their supervising federal banking agencies. Small supervised lenders and mortgagees would only be required to submit audited financial statements if HUD determines that the supervised lenders or mortgagees pose heightened risk to the FHA insurance fund.
This rule does not impact FHA's annual audited financial statements submission requirement for nonsupervised and large supervised lenders and mortgagees. The rule also does not impact those supervised lenders and mortgagees with consolidated assets in an amount that requires that lenders or mortgagees submit audited financial statements to their respective supervising federal banking agencies. Finally, HUD has
Interested persons are invited to submit comments regarding this proposed rule to the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 7th Street SW., Room 10276, Washington, DC 20410–0500. Communications must refer to the above docket number and title. There are two methods for submitting public comments. All submissions must refer to the above docket number and title.
1.
2.
To receive consideration as public comments, comments must be submitted through one of the two methods specified above. Again, all submissions must refer to the docket number and title of the rule.
Richard Toma, Deputy Director, Office of Lender Activities and Program Compliance, Office of Housing, Department of Housing and Urban Development, 490 L'Enfant Plaza East SW., Room P3214, Washington, DC 20024–8000; telephone number 202–708–1515 (this is not a toll-free number). Persons with hearing or speech impairments may access this number through TTY by calling the toll-free Federal Relay Service at 800–877–8339.
As part of HUD's efforts to strengthen risk management of the FHA insurance funds, HUD published a final rule on April 20, 2010, entitled, “Federal Housing Administration: Continuation of FHA Reform—Strengthening Risk Management Through Responsible FHA-Approved Lenders” (75 FR 20718). The April 20, 2010, final rule increased the net worth requirements for FHA-approved lenders and mortgagees, eliminated HUD's approval of loan correspondents, and amended the general approval standards for lenders and mortgagees. The goal of increasing the net worth requirements was to ensure that FHA-approved lenders and mortgagees are sufficiently capitalized. To monitor compliance with the net worth requirements, the April 20, 2010, final rule requires all lenders and mortgagees to provide annual audited financial statements within 90 days of their fiscal year ends as a condition of FHA approval and recertification. The requirement for the submission of annual audited financial statements applies to all FHA-approved lenders and mortgagees, irrespective of their net worth. Interested readers should refer to the preamble of the April 20, 2010, final rule for additional information regarding the risk management amendments to the FHA program requirements.
Since publication of the April 20, 2010, final rule, HUD has determined that the FHA requirement for all supervised lenders and mortgagees to submit annual audited financial statements may prove to be prohibitively expensive for small supervised lenders and mortgagees who wish to participate in FHA programs. While HUD takes its counterparty risk management responsibilities seriously, HUD seeks to balance its management of risk with the execution of its mission. In order to ensure that FHA products and programs remain available in the communities served by small supervised lenders and mortgagees, HUD proposes through this rule to modify its annual audited financial statements reporting requirement for these institutions.
Lenders and mortgagees supervised by the Board of Governors of the Federal Reserve System; the Federal Deposit Insurance Corporation (FDIC); and the National Credit Union Administration (NCUA) (collectively the “federal banking agencies”), are required to submit audited financial statements to their respective supervising federal banking agencies where the lenders' or mortgagees' consolidated assets meet or exceed the minimum thresholds established by those federal banking agencies; which thresholds are all currently $500 million or more in consolidated assets and are currently codified at 12 CFR 363.1(a) and 12 CFR 715.4(c). Lenders and mortgagees whose consolidated assets for the applicable fiscal year are less than their supervising federal banking agency's threshold for submission of audited financial statements (hereinafter “small lenders and mortgagees”) are required to submit unaudited financial regulatory reports. These unaudited financial regulatory reports currently include a consolidated or fourth quarter Report of Condition and Income (Federal Financial Institutions Examination Council forms 031 and 041, also known as the “Call Report”), a consolidated or fourth quarter Thrift Financial Report, and a consolidated or fourth quarter NCUA Call Report (NCUA Form 5300 or 5310).
In an effort to be consistent with the financial reporting requirements designated by the supervisory federal banking agencies for small lenders and mortgagees, HUD will no longer require small supervised lenders or mortgagees to submit audited financial statements. Instead, HUD will require that small supervised lenders and mortgagees submit the unaudited financial regulatory reports that they are required to submit to their supervising federal banking agencies. HUD has determined that the financial regulatory reports required by the federal banking agencies contain sufficient information for HUD to ensure that small supervised lenders and mortgagees are suitably capitalized
In order to manage the risk to the FHA insurance fund, HUD retains the right to request additional financial documentation, up to and including audited financial statements, if HUD determines that a small supervised lender or mortgagee poses a heightened risk to the FHA insurance fund. HUD has determined that the following factors are relevant, but not exhaustive, in determining if a small supervised lender or mortgagee poses a heightened risk to the FHA insurance fund: (1) Failing to provide required financial submissions under § 202.6(c)(2) within the required 90-day period following the lender's or mortgagee's fiscal year end; (2) maintaining insufficient adjusted net worth or unrestricted liquid assets as required by § 202.5(n); (3) reporting opening cash and equity balances that do not agree with the prior year's reported cash and equity balances; (4) experiencing an operating loss of 20 percent or greater of the lender's or mortgagee's net worth for the annual reporting period as governed by § 202.5(m)(1); (5) experiencing an increase in loan volume over the prior 12-month period, determined by the Secretary to be significant; (6) undertaking significant changes to business operations, such as a merger or acquisition; and (7) other factors that the Secretary considers appropriate in indicating a heightened risk to the FHA insurance fund.
Consistent with the requirements of the federal banking agencies, HUD will continue to require audited financial statements for supervised lenders and mortgagees whose consolidated assets meet or exceed the threshold set by the federal banking agencies, presently located at 12 CFR 363.1(a) and 12 CFR 715.4(c)—currently $500 million or more in consolidated assets. Because the asset threshold established by the federal banking agencies may change over time, this proposed rule references the regulations of the federal banking agencies instead of a numeric figure. HUD specifically seeks comments from small supervised lenders and mortgagees on whether they are required to provide annual audited financial statement to any other regulating body, such as a state agency.
HUD has taken the opportunity afforded by this proposed rule to make three conforming amendments to current regulations regarding reporting requirements for FHA-approved supervised lenders and mortgagees. These nonsubstantive amendments will codify existing requirements and correct a regulatory citation. The amendments are as follows:
1.
2.
3.
The total cost savings from the reporting and recordkeeping burden for small supervised lenders and mortgagees would be approximately $110,770. HUD currently has 1,471 approved supervised lenders and mortgagees who are required to submit annual audited financial statements, of which HUD approximates that 857 are small supervised lenders and mortgagees whom this rule will benefit. Under this proposed rule, small supervised lenders and mortgagees would no longer be required to complete and submit the Online Annual Financial Statements and Reports, but would instead submit an electronic copy of the unaudited financial regulatory report that aligns with their fiscal year end, as required by and submitted to their supervising federal banking agency. Currently it takes a lender or mortgagee 3 hours to complete the required Online Annual Financial Statements and Reports submission.
The information collection requirements for this proposed rule have been submitted to the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501–3520). In accordance with the Paperwork Reduction Act, an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information, unless the collection displays a currently valid OMB control number.
This proposed rule would amend 24 CFR part 202. Part 202 currently contains the collection of information approved by OMB, and the OMB control number is 2502–0005. The collection title is, “HUD–FHA Title I/Title II Lender Approval, Annual Recertification, Noncompliance Forms, Reports, Ginnie Mae Issuer Approval, and Credit Watch Termination Reinstatement.” As proposed below, this rule would amend the collection of information currently required by “item n,” the online submission of annual audited financial statements by Title I and Title II nonsupervised lenders, supervised lenders and nonsupervised loan correspondents, of OMB control number 2502–0005 (hereinafter, Annual Audited Financial Statement). This proposed rule is estimated to reduce the burden in the existing information collection requirement as follows:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility.
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information.
(3) Enhance the quality, utility, and clarity of the information to be collected.
(4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology (e.g., by permitting electronic submission of responses).
Interested persons are invited to submit comments regarding the information collection requirements in this rule. Comments must refer to the proposed rule by name and docket number (FR–5583–P–01) and must be sent to:
Interested persons may submit comments regarding the information collection requirements electronically through the Federal eRulemaking Portal at
Under Executive Order 12866 (Regulatory Planning and Review), a determination must be made whether a regulatory action is significant and, therefore, subject to review by OMB in accordance with the requirements of the order. Executive Order 13563 (Improving Regulations and Regulatory Review) directs executive agencies to analyze regulations that are “outmoded, ineffective, insufficient, or excessively burdensome, and to modify, streamline, expand, or repeal them in accordance with what has been learned.” Executive Order 13563 also directs that, where relevant, feasible, and consistent with regulatory objectives and to the extent permitted by law, agencies are to identify and consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public. Accordingly, HUD has determined that aligning FHA's financial reporting requirements for small supervised lenders and mortgagees with the financial reporting requirements of the federal banking agencies eliminates unnecessary financial and administrative burdens posed by FHA's current requirement to submit an audited financial statement, and thereby enhances the ability of small supervised lenders and mortgagees to participate in FHA programs. HUD has concluded that the federal banking agencies have controls in place through examination and monitoring to takeover institutions experiencing significant financial distress that pose a risk to depositors. Therefore, the information within the financial regulatory reports being provided to the federal banking agencies is comprehensive and provides the data necessary for FHA to analyze a small supervised lender's or mortgagee's net worth and assets to determine if financial risk is posed to the FHA fund. In a case where a small supervised lender or mortgagee shows sign of financial risk, HUD retains the right to request additional financial documentation, up to and including audited financial statements. As a result, this rule was determined to not be a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, and therefore was not reviewed by OMB.
The Regulatory Flexibility Act (RFA) (5 U.S.C. 601
Notwithstanding HUD's determination that this rule would not have a significant effect on a substantial number of small entities, HUD specifically invites comments regarding any less burdensome alternatives to this rule that would meet HUD's objectives as described in the preamble to this rule.
This rule does not direct, provide for assistance or loan and mortgage insurance for, or otherwise govern or regulate real property acquisition, disposition, leasing, rehabilitation, alteration, demolition, or new construction. Nor does it establish, revise, or provide for standards for construction or construction materials, manufactured housing, or occupancy. This rule is limited to the procedures governing the submission of financial reports by small supervised lenders and mortgagees applying to participate, or recertifying for participation, in FHA's single-family programs. Accordingly, under 24 CFR 50.19(c)(1), this rule is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321).
Executive Order 13132 (entitled “Federalism”) prohibits an agency from publishing any rule that has federalism implications if the rule either (1) imposes substantial direct compliance costs on state and local governments and is not required by statute, or (2) preempts state law, unless the agency meets the consultation and funding requirements of section 6 of the Executive Order. This rule would not have federalism implications and would not impose substantial direct compliance costs on state and local governments or preempt state law within the meaning of the Executive Order.
Title II of the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531–1538) (UMRA) establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and on the private sector. This proposed rule would not impose any federal mandates on any state, local, or tribal governments, or on the private sector, within the meaning of the UMRA.
The Catalogue of Federal Domestic Assistance Number for the principal FHA single-family mortgage insurance program is 14.117.
Administrative practice and procedure, Aged, Claims, Crime, Government contracts, Grant programs—housing and community development, Individuals with disabilities, Intergovernmental relations, Loan programs—housing and community development, Low and moderate income housing, Mortgage insurance, Penalties, Pets, Public housing, Rent subsidies, Reporting and recordkeeping requirements, Social security, Unemployment compensation, Wages.
Administrative practice and procedure, Home improvement, Manufactured homes, Mortgage insurance, Reporting and recordkeeping requirements.
Accordingly, for the reasons stated in the preamble, HUD proposes to amend 24 CFR parts 5 and 202 to read as follows:
42 U.S.C. 1437a, 1437c, 1437d, 1437f, 1437n, 3535(d), Sec. 327, Pub. L. 109–115, 119 Stat. 2936, and Sec. 607, Pub. L. 109–162, 119 Stat. 3051.
(a) * * *
(5) HUD-approved Title I and Title II supervised and nonsupervised lenders and mortgagees.
12 U.S.C. 1703, 1709 and 1715b; 42 U.S.C. 3535(d).
(g)
(b) * * *
(4)
(i) Comply with the financial reporting requirements in 24 CFR part 5, subpart H. Audit reports shall be based on audits performed by a certified public accountant, or by an independent public accountant licensed by a regulatory authority of a State or other political subdivision of the United States on or before December 31, 1970, and shall include:
(A) Financial statements in a form acceptable to the Secretary, including a balance sheet and a statement of
(B) Such other financial information as the Secretary may require to determine the accuracy and validity of the audit report.
(ii) Submit a report on compliance tests prescribed by the Secretary.
(c)
(1)
(i)
(ii)
(2)
(3)
(i) Failing to provide required financial submissions under § 202.6(c)(2) within the required 90-day period following the lender's or mortgagee's fiscal year end;
(ii) Maintaining insufficient adjusted net worth or unrestricted liquid assets as required by § 202.5(n);
(iii) Reporting opening cash and equity balances that do not agree with the prior year's reported cash and equity balances;
(iv) Experiencing an operating loss of 20 percent or greater of the lender's or mortgagee's net worth for the annual reporting period as governed by § 202.5(m)(1);
(v) Experiencing an increase in loan volume over the prior 12-month period, determined by the Secretary to be significant;
(vi) Undertaking significant changes to business operations, such as a merger or acquisition; and
(vii) Other factors that the Secretary considers appropriate in indicating a heightened risk to the FHA insurance fund.
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking by cross-reference to temporary regulations.
In the Rules and Regulations section of this issue of the
Written or electronic comments must be received by July 17, 2013.
Send submissions to: CC:PA:LPD:PR (REG–154563–12), room 5203, Internal Revenue Service, PO Box 7604, Ben Franklin Station, Washington, DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG–154563–12), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC, or sent electronically via the Federal eRulemaking Portal at
Concerning the proposed regulations, Pamela Lew, (202) 622–3950; concerning submissions of comments, Oluwafunmilayo (Funmi) Taylor, (202) 622–7180 (not toll-free numbers).
Temporary regulations in the Rules and Regulations section of this issue of the
A number of commenters have indicated that compliance with basis reporting requirements and the use of basis and other information reported by brokers will require considerable resources and effort on the part of return preparers and information recipients. The Treasury Department and the IRS are continuing to review all aspects of the information reporting process and are exploring ways to reduce the compliance burden for both brokers and for information recipients.
It has been determined that this notice of proposed rulemaking is not a significant regulatory action as defined in Executive Order 12866, as supplemented by Executive Order 13563. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations, and because the regulations
Pursuant to section 7805(f) of the Internal Revenue Code, this notice of proposed rulemaking has been submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on its impact on small businesses.
Before these proposed regulations are adopted as final regulations, consideration will be given to any written (a signed original and eight (8) copies) or electronic comments that are submitted timely to the IRS as prescribed in the preamble under the “
The principal author of these regulations is Pamela Lew, Office of Associate Chief Counsel (Financial Institutions and Products). However, other personnel from the IRS and the Treasury Department participated in their development.
Income Taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is proposed to be amended as follows:
26 U.S.C. 7805 * * * Section 1.6049–9 also issued under 26 U.S.C. 6049(a). * * *
[The text of proposed § 1.6049–9 is the same as the text of § 1.6049–9T published elsewhere in this issue of the
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing significant new use rules (SNURs) under the Toxic Substances Control Act (TSCA) for eight chemical substances which were the subject of premanufacture notices (PMNs) P–11–327, P–11–328, P–11–329, P–11–330, P–11–331, P–11–332, P–12–298, and P–12–299. This action would require persons who intend to manufacture, import, or process any of the chemical substances for an activity that is designated as a significant new use by this proposed rule to notify EPA at least 90 days before commencing that activity. The required notification would provide EPA with the opportunity to evaluate the intended use and, if necessary, to prohibit or limit the activity before it occurs.
Comments must be received on or before May 20, 2013.
Submit your comments, identified by docket identification (ID) number EPA–HQ–OPPT–2012–0740, by one of the following methods:
•
•
•
You may be potentially affected by this action if you manufacture, import, process, or use the chemical substances contained in this proposed rule. The following list of North American Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers determine whether this document applies to them. Potentially affected entities may include:
• Manufacturers, importers, or processors of one or more subject chemical substances (NAICS codes 325 and 324110), e.g., chemical manufacturing and petroleum refineries.
This action may also affect certain entities through pre-existing import certification and export notification rules under TSCA. Chemical importers are subject to the TSCA section 13 (15 U.S.C. 2612) import certification requirements promulgated at 19 CFR 12.118 through 12.127; see also 19 CFR 127.28. Chemical importers must certify that the shipment of the chemical substance complies with all applicable rules and orders under TSCA. Importers of chemicals subject to a final SNUR must certify their compliance with the SNUR requirements. The EPA policy in support of import certification appears at 40 CFR part 707, subpart B. In addition, any persons who export or intend to export a chemical substance that is the subject of a proposed or final SNUR are subject to the export notification provisions of TSCA section 12(b) (15 U.S.C. 2611(b)) (see § 721.20) and must comply with the export notification requirements in 40 CFR part 707, subpart D.
1.
2.
i. Identify the document by docket ID number and other identifying information (subject heading,
ii. Follow directions. The Agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.
iii. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
iv. Describe any assumptions and provide any technical information and/or data that you used.
v. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
vi. Provide specific examples to illustrate your concerns and suggest alternatives.
vii. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.
viii. Make sure to submit your comments by the comment period deadline identified.
EPA is proposing these SNURs under section 5(a)(2) of TSCA for eight chemical substances which were the subject of PMNs P–11–327, P–11–328, P–11–329, P–11–330, P–11–331, P–11–332, P–12–298, and P–12–299. These SNURs would require persons who intend to manufacture, import, or process any of these chemical substances for an activity that is designated as a significant new use to notify EPA at least 90 days before commencing that activity.
In the
Section 5(a)(2) of TSCA (15 U.S.C. 2604(a)(2)) authorizes EPA to determine that a use of a chemical substance is a “significant new use.” EPA must make this determination by rule after considering all relevant factors, including the four bulleted TSCA section 5(a)(2) factors listed in Unit III. Once EPA determines that a use of a chemical substance is a significant new use, TSCA section 5(a)(1)(B) requires persons to submit a significant new use notice (SNUN) to EPA at least 90 days before they manufacture, import, or process the chemical substance for that use. Persons who must report are described in § 721.5.
General provisions for SNURs appear in 40 CFR part 721, subpart A. These provisions describe persons subject to the rule, recordkeeping requirements, exemptions to reporting requirements, and applicability of the rule to uses occurring before the effective date of the rule. Provisions relating to user fees appear at 40 CFR part 700. According to § 721.1(c), persons subject to these SNURs must comply with the same notice requirements and EPA regulatory procedures as submitters of PMNs under TSCA section 5(a)(1)(A). In particular, these requirements include the information submission requirements of TSCA sections 5(b) and 5(d)(1), the exemptions authorized by TSCA sections 5(h)(1), (h)(2), (h)(3), and (h)(5), and the regulations at 40 CFR part 720. Once EPA receives a SNUN, EPA may take regulatory action under TSCA section 5(e), 5(f), 6, or 7 to control the
Section 5(a)(2) of TSCA states that EPA's determination that a use of a chemical substance is a significant new use must be made after consideration of all relevant factors, including:
• The projected volume of manufacturing and processing of a chemical substance.
• The extent to which a use changes the type or form of exposure of human beings or the environment to a chemical substance.
• The extent to which a use increases the magnitude and duration of exposure of human beings or the environment to a chemical substance.
• The reasonably anticipated manner and methods of manufacturing, processing, distribution in commerce, and disposal of a chemical substance.
In addition to these factors enumerated in TSCA section 5(a)(2), the statute authorized EPA to consider any other relevant factors.
To determine what would constitute a significant new use for the eight chemical substances that are the subject of this proposed rule, EPA considered relevant information about the toxicity of the chemical substances, likely human exposures and environmental releases associated with possible uses, and the four bulleted TSCA section 5(a)(2) factors listed in this unit.
EPA is proposing significant new use and recordkeeping requirements for eight chemical substances in 40 CFR part 721, subpart E. In this unit, EPA provides the following information for each chemical substance:
• PMN number.
• Chemical name (generic name, if the specific name is claimed as CBI).
• Chemical Abstracts Service (CAS) number (if assigned for non-confidential chemical identities).
• Basis for the TSCA section 5(e) consent order or, for non-section 5(e) SNURs, the basis for the SNUR (i.e., SNURs without TSCA section 5(e) consent orders).
• Tests recommended by EPA to provide sufficient information to evaluate the chemical substance (see Unit VII. for more information).
• CFR citation assigned in the regulatory text section of this proposed rule.
The regulatory text section of this proposed rule specifies the activities designated as significant new uses.
This proposed rule includes PMN substances P–11–327, P–11–328, P–11–329, P–11–330, P–11–331, and P–11–332, that are subject to a “risk-based” consent order under TSCA section 5(e)(1)(A)(ii)(I) where EPA determined that activities associated with the PMN substances may present unreasonable risk to human health or the environment. This consent order requires protective measures to limit exposures or otherwise mitigate the potential unreasonable risk. The so-called “section 5(e) SNURs” on these PMN substances are proposed pursuant to § 721.160, and are based on and consistent with the provisions in the underlying consent order. The section 5(e) SNURs designate as a “significant new use” the absence of the protective measures required in the corresponding consent order.
This proposed rule also includes a SNUR on PMN substances P–12–298 and P–12–299 that were not subject to a consent order under TSCA section 5(e). In this case, EPA did not find that the use scenario described in the PMNs triggered the determinations set forth under TSCA section 5(e). However, EPA does believe that certain changes from the use scenario described in the PMNs could result in increased exposures, thereby constituting a “significant new use.” This so-called “non-section 5(e) SNUR” is proposed pursuant to § 721.170. EPA has determined that every activity designated as a “significant new use” in all non-section 5(e) SNURs issued under § 721.170 satisfies the two requirements stipulated in § 721.170(c)(2), i.e., these significant new use activities, “(i) are different from those described in the premanufacture notice for the substance, including any amendments, deletions, and additions of activities to the premanufacture notice, and (ii) may be accompanied by changes in exposure or release levels that are significant in relation to the health or environmental concerns identified” for the PMN substance.
1. Use of personal protective equipment including dermal protection when there is potential dermal exposure and a National Institute for Occupational Safety and Health
2. No use of the substances resulting in surface water concentrations exceeding 5 ppb of the combination of these PMN substances.
3. Establishment and use of a hazard communication program. The SNUR designates as a “significant new use” the absence of these protective measures.
During review of the PMNs submitted for the eight chemical substances that are subject to these proposed SNURs, EPA concluded that for six of the substances, regulation was warranted under TSCA section 5(e), pending the development of information sufficient to make reasoned evaluations of the health and environmental effects of the chemical substances. For two of the eight substances, where the uses are not regulated under a TSCA section 5(e) consent order, EPA determined that one or more of the criteria of concern established at § 721.170 were met. The basis for these findings is outlined in Unit IV.
EPA is proposing these SNURs for specific chemical substances that have undergone premanufacture review because the Agency wants to achieve the following objectives with regard to the significant new uses designated in this proposed rule:
• EPA would receive notice of any person's intent to manufacture, import, or process a listed chemical substance for the described significant new use before that activity begins.
• EPA would have an opportunity to review and evaluate data submitted in a SNUN before the notice submitter begins manufacturing, importing, or processing a listed chemical substance for the described significant new use.
• EPA would be able to regulate prospective manufacturers, importers, or processors of a listed chemical substance before the described significant new use of that chemical substance occurs, provided that regulation is warranted pursuant to TSCA sections 5(e), 5(f), 6, or 7.
• EPA would ensure that all manufacturers, importers, and processors of the same chemical substance that is subject to a TSCA section 5(e) consent order are subject to similar requirements.
Issuance of a SNUR for a chemical substance does not signify that the chemical substance is listed on the TSCA Chemical Substance Inventory (TSCA Inventory). Guidance on how to determine if a chemical substance is on the TSCA Inventory is available on the Internet at
To establish a significant new use, EPA must determine that the use is not ongoing. The chemical substances subject to this proposed rule have undergone premanufacture review. In cases where EPA has not received a notice of commencement (NOC) and the chemical substance has not been added to the TSCA Inventory, no person may commence such activities without first submitting a PMN. Therefore, for chemical substances for which an NOC has not been submitted EPA concludes that the designated significant new uses are not ongoing.
When chemical substances identified in this proposed rule are added to the TSCA Inventory, EPA recognizes that, before the final rule is issued, other persons might engage in a use that has been identified as a significant new use. However, TSCA section 5(e) consent orders have been issued for six of the eight chemical substances, and the PMN submitters are prohibited by the TSCA section 5(e) consent orders from undertaking activities which would be designated as significant new uses. The other two chemical substances contained in this proposed rule are not regulated with TSCA section 5(e) consent orders. The identities of these two chemical substances have been claimed as confidential, and EPA has received no post-PMN
If uses begun after the direct final rule was published on November 2, 2012, were considered ongoing rather than new, any person could defeat the SNUR by initiating the significant new use
EPA recognizes that TSCA section 5 does not require developing any particular test data before submission of a SNUN. The two exceptions are:
1. Development of test data is required where the chemical substance subject to the SNUR is also subject to a test rule under TSCA section 4 (see TSCA section 5(b)(1)).
2. Development of test data may be necessary where the chemical substance has been listed under TSCA section 5(b)(4) (see TSCA section 5(b)(2)).
In the absence of a TSCA section 4 test rule or a TSCA section 5(b)(4) listing covering the chemical substance, persons are required only to submit test data in their possession or control and to describe any other data known to or reasonably ascertainable by them (see § 720.50). However, upon review of PMNs and SNUNs, the Agency has the authority to require appropriate testing. In cases where EPA issued a TSCA section 5(e) consent order that requires or recommends certain testing, Unit IV. lists those tests. Unit IV. also lists recommended testing for non-5(e) SNURs. Descriptions of tests are provided for informational purposes. EPA strongly encourages persons, before performing any testing, to consult with the Agency pertaining to protocol selection. To access the OCSPP test guidelines referenced in this document electronically, please go to
The recommended tests specified in Unit IV. may not be the only means of addressing the potential risks of the chemical substance. However, submitting a SNUN without any test data may increase the likelihood that EPA will take action under TSCA section 5(e), particularly if satisfactory test results have not been obtained from a prior PMN or SNUN submitter. EPA recommends that potential SNUN submitters contact EPA early enough so that they will be able to conduct the appropriate tests.
SNUN submitters should be aware that EPA will be better able to evaluate SNUNs which provide detailed information on the following:
• Human exposure and environmental release that may result from the significant new use of the chemical substances.
• Potential benefits of the chemical substances.
• Information on risks posed by the chemical substances compared to risks posed by potential substitutes.
According to § 721.1(c), persons submitting a SNUN must comply with the same notice requirements and EPA regulatory procedures as persons submitting a PMN, including submission of test data on health and environmental effects as described in § 720.50. SNUNs must be submitted on EPA Form No. 7710–25, generated using e–PMN software, and submitted to the Agency in accordance with the procedures set forth in §§ 720.40 and 721.25. E–PMN software is available electronically at
EPA has evaluated the potential costs of establishing SNUN requirements for potential manufacturers, importers, and processors of the chemical substances during the development of the direct final rule. EPA's complete economic analysis is available in the docket under docket ID number EPA–HQ–OPPT–2012–0740.
This proposed rule would establish SNURs for eight chemical substances that were the subject of PMNs, and in six cases, a TSCA section 5(e) consent order. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled
According to the PRA, 44 U.S.C. 3501
The information collection requirements related to this action have already been approved by OMB pursuant to PRA under OMB control number 2070–0012 (EPA ICR No. 574). This action would not impose any burden requiring additional OMB approval. If an entity were to submit a SNUN to the Agency, the annual burden is estimated to average between 30 and 170 hours per response. This burden estimate includes the time needed to review instructions, search existing data sources, gather and maintain the data needed, and complete, review, and submit the required SNUN.
Send any comments about the accuracy of the burden estimate, and any suggested methods for minimizing respondent burden, including through the use of automated collection techniques, to the Director, Collection Strategies Division, Office of Environmental Information (2822T), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460–0001. Please remember to include the OMB control number in any correspondence, but do not submit any completed forms to this address.
On February 18, 2012, EPA certified pursuant to RFA section 605(b) (5 U.S.C. 601
1. A significant number of SNUNs would not be submitted by small entities in response to the SNUR.
2. The SNUR submitted by any small entity would not cost significantly more than $8,300. A copy of that certification is available in the docket for this proposed rule.
This proposed rule is within the scope of the February 18, 2012 certification. Based on the Economic Analysis discussed in Unit IX. and EPA's experience promulgating SNURs (discussed in the certification), EPA believes that the following are true:
• A significant number of SNUNs would not be submitted by small entities in response to the SNUR.
• Submission of the SNUN would not cost any small entity significantly more than $8,300.
Therefore, the promulgation of these SNURs would not have a significant economic impact on a substantial number of small entities.
Based on EPA's experience with proposing and finalizing SNURs, State, local, and Tribal governments have not been impacted by these rulemakings, and EPA does not have any reasons to believe that any State, local, or Tribal government would be impacted by this proposed rule. As such, EPA has determined that this proposed rule would not impose any enforceable duty, contain any unfunded mandate, or otherwise have any effect on small governments subject to the requirements of UMRA sections 202, 203, 204, or 205 (2 U.S.C. 1501
This action would not have a substantial direct effect on 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, as specified in Executive Order 13132, entitled
This proposed rule would not have Tribal implications because it is not expected to have substantial direct effects on Indian Tribes. This proposed rule would not significantly nor uniquely affect the communities of Indian Tribal governments, nor would it involve or impose any requirements that affect Indian Tribes. Accordingly, the requirements of Executive Order 13175, entitled
This action is not subject to Executive Order 13045, entitled
This proposed rule is not subject to Executive Order 13211, entitled
In addition, since this action would not involve any technical standards the National Technology Transfer and Advancement Act (NTTAA), section 12(d) (15 U.S.C. 272 note), would not apply to this action.
This action does not entail special considerations of environmental justice related issues as delineated by Executive Order 12898, entitled
Environmental protection, Chemicals, Hazardous substances, Reporting and recordkeeping requirements.
Therefore, it is proposed that 40 CFR part 721 be amended as follows:
15 U.S.C. 2604, 2607, and 2625(c).
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respiratory requirements listed in paragraph (a)(2)(i) of this section, a manufacturer, importer, or processor may choose to follow the new chemical exposure limit (NCEL) provisions listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.32 milligram/cubic meter (mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
Federal Communications Commission.
Proposed rule.
In this document, the Wireline Competition Bureau adds a new virtual workshop discussion topic, entitled “Operating Expenses Input Values” to seek public input.
Comments are due on or before April 25, 2013.
If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
You may submit comments, identified by WC Docket No. 10–90, by any of the following methods:
Katie King, Wireline Competition Bureau at (202) 418–7491 or TTY (202) 418–0484.
This is a synopsis of the Wireline Competition Bureau's Public Notice in WC Docket No. 10–90; DA 13–704, released April 11, 2013, as well as information posted online in the Wireline Competition Bureau's Virtual Workshop. The complete text of the Public Notice is available for inspection and copying during normal business hours in the FCC Reference Information Center, Portals II, 445 12th Street SW., Room CY–A257, Washington, DC 20554. These documents may also be purchased from the Commission's duplicating contractor, Best Copy and Printing, Inc. (BCPI), 445 12th Street SW., Room CY–B402, Washington, DC 20554, telephone (800) 378–3160 or (202) 863–2893, facsimile (202) 863–2898, or via the Internet at
1. On Tuesday, October 9, 2012, the Wireline Competition Bureau (Bureau) announced the commencement of a virtual workshop to solicit input and facilitate discussion on topics related to the development and adoption of the forward-looking cost model for Connect America Phase II. To date, the Bureau has sought comment on 22 different topics in the virtual workshop.
2. Today, the Bureau adds a new virtual workshop discussion topic, entitled “Operating Expenses Input Values.” Responses should be submitted in the virtual workshop no later than April 25, 2013. Parties can participate in the virtual workshop by visiting the Connect America Fund Web page,
3. Comments from the virtual workshop will be included in the official public record of this proceeding. The Bureau will not rely on anonymous comments posted during the workshop in reaching decisions regarding the model. Participants should be aware that identifying information from parties that post material in the virtual workshop will be publicly available for inspection upon request, even though such information may not be posted in the workshop forums.
4. As required by the Regulatory Flexibility Act of 1980, as amended (RFA), the Bureau prepared an Initial Regulatory Flexibility Analysis (IRFA), included as part of the
5. This document does not contain proposed information collection(s) subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104–13. In addition, therefore, it does not contain any new or modified information collection burden for small business concerns with fewer than 25 employees, pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107–198,
6.
7.
8.
9.
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
DoD, GSA, and NASA are proposing to amend the Federal Acquisition Regulation (FAR) to require the use of Commercial and Government Entity (CAGE) codes, including North Atlantic Treaty Organization (NATO) CAGE (NCAGE) codes for foreign entities, for awards valued at greater than the micro-purchase threshold. The CAGE code is a five-character identification number used extensively within the Federal Government. The proposed rule will also require offerors, if owned or controlled by another business entity, to identify that entity during System for Award Management (SAM) registration.
Interested parties should submit written comments to the Regulatory Secretariat at one of the addressees shown below on or before June 17, 2013 to be considered in the formation of the final rule.
Submit comments in response to FAR Case 2012–024 by any of the following methods:
•
•
•
Mr. Edward Loeb, Procurement Analyst, at 202–501–0650 for clarification of content. For information pertaining to status or publication schedules, contact the Regulatory Secretariat at 202–501–4755. Please cite FAR Case 2012–024.
DoD, GSA, and NASA are proposing to revise the FAR with a new provision to require that offerors provide their CAGE codes to contracting officers and that, if owned or controlled by another entity, offerors will provide, in a new provision with their representations and certifications, the CAGE code and name of such entity or entities. For those offerors located in the United States or its outlying areas that register in SAM, a CAGE code is assigned as part of the registration process. Note: The text of this proposed rule uses the new FAR reference, SAM for CCR and ORCA, as there is a pending FAR rule (FAR Case 2012–033, System for Award Management Name Change, Phase 1 Implementation) which will make a global update to all of the existing references to CCR and ORCA throughout the FAR to the SAM designation.
If registration is not required, a CAGE code will be requested and obtained from the Defense Logistics Agency, Logistics Information Service. A CAGE code is not required when a condition described at FAR 4.605(c)(2) applies and the acquisition is funded by an agency other than DoD or NASA. Offerors located outside the United States will obtain an NCAGE from their NATO Codification Bureau or, if not a NATO member or sponsored nation, from the NATO Maintenance and Supply Agency (NAMSA).
The Federal procurement community continues to strive toward greater measures of transparency and reliability of data, which facilitates achievement of rigorous accountability of procurement dollars and processes and compliance with regulatory and statutory acquisition requirements,
To further the desired increases in traceability and transparency, this rule proposes use of the unique identification that a CAGE code provides coupled with vendor representation of ownership and owner CAGE code. The CAGE code is a five-character identification number used extensively within the Federal Government and will provide for standardization across the Federal Government. This proposed rule will—
• Support successful implementation of business tools that seek insight into Federal spending patterns across corporations;
• Facilitate legal traceability in the tracking of performance issues across corporations;
• Provide insight on contractor personnel outside the United States; and
• Support supply chain traceability and integrity efforts.
At FAR 4.1202 a new provision for ownership or control of offeror is added to the list of representations and certifications under FAR 52.204–8, Annual Representations and Certifications.
A new subpart is proposed to include scope, policy, and definitions for the subpart. Offerors are required to provide
A definition of “Commercial and Government Entity” code is provided. The definition encompasses both CAGE code, for entities located in the United States and its outlying areas, and NCAGE code if the code is assigned by a NATO Codification Bureau or NAMSA.
The rule proposes definitions of ownership and intends their use only in order to determine how entities relate to one another in terms of hierarchical relationship(s). The rule does not intend to impact or supersede the definitions of “contractor” or “ownership” as described in other parts of the FAR (
“Highest-level owner” means the business entity that owns or controls one or more business entities that own or control the offeror.
“Immediate owner” means the business entity that has the most direct and proximate ownership or control of the offeror.
“Owner” means the entity, other than the offeror, that is affiliated with the offeror through control of the offeror as described in this definition or, in the case of a small business, as provided in FAR part 19 and 13 CFR part 121. Business concerns, organizations, or individuals are affiliates of each other if, directly or indirectly, either one controls or has the power to control the other, or a third party controls or has the power to control both. The two types of owners are immediate owners and highest-level owners, respectively, and these owners may be the same for some entities. Indicators of control include, but are not limited to, interlocking management or ownership, identity of interests among family members, shared facilities and equipment, and the common use of employees.
Changes to the list of other required provisions and clauses at FAR 12.301(d) are proposed to make CAGE code reporting and maintenance applicable to commercial items by including a new provision, FAR 52.204–XX, Commercial and Government Entity Code Reporting, and a new clause, FAR 52.204–ZZ, Commercial and Government Entity Code Maintenance.
Updates are provided to correct paragraph numbers referencing the provision 52.204–8.
Two new provisions are proposed, two existing provisions are amended, and one new clause is proposed:
Provision FAR 52.204–XX, Commercial and Government Entity Code Reporting, requires offerors to provide their CAGE codes and contains information on obtaining CAGE codes.
Provision FAR 52.204–YY, Ownership or Control of Offeror, calls for offerors to identify if they are owned or controlled by another entity and to provide the legal name and CAGE code of such entity, if identified.
The proposed rule will amend FAR 52.204–8, Annual Representations and Certifications, by including the new provision FAR 52.204–YY, Ownership or Control of Offeror, and FAR 52.212–3, Offeror Representations and Certifications—Commercial Items, by including definitions and ownership or control representations.
Clause FAR 52.204–ZZ, Commercial and Government Entity Code Maintenance, provides instructions to contractors to maintain accurate CAGE information in the CAGE file and to inform their contracting officer if their CAGE code changes.
Executive Orders (E.O.s) 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of E.O. 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
DoD, GSA, and NASA do not expect this rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act 5 U.S.C. 601,
This rule would affect offerors that currently do not have a CAGE code and/or are owned by another entity. This proposed rule would require those offerors without a CAGE code and that do not register through SAM, to request and obtain a CAGE code. In FY2011, awards were made to 2,154 unique vendors that were not required to register through SAM. Of these, 741 were small business vendors. In addition, the proposed rule requires offerors to represent that, if owned or controlled by another entity, they have entered the CAGE code and the legal name of that entity. The Federal Government estimates that it received offers from 413,808 unique vendors in FY2011. Approximately 275,872 of these offers were by unique small businesses and it is estimated that this number of small businesses will be required to respond to the proposed ownership provision.
The Regulatory Secretariat has submitted a copy of the IRFA to the Chief Counsel for Advocacy of the Small Business Administration. A copy of the IRFA may be obtained from the Regulatory Secretariat. DoD, GSA, and NASA invite comments from small business concerns and other interested parties on the expected impact of this rule on small entities.
DoD, GSA, and NASA will also consider comments from small entities concerning the existing regulations in subparts affected by this rule consistent with 5 U.S.C. 610. Interested parties must submit such comments separately and should cite 5 U.S.C 610 (FAR Case 2012–024), in correspondence.
The Paperwork Reduction Act (44 U.S.C. chapter 35) applies. The proposed rule contains information collection requirements. Accordingly, the Regulatory Secretariat has submitted a request for approval of a new information collection requirement concerning Commercial and Government Entity Code (FAR Case 2012–024) to the Office of Management and Budget.
Public reporting burden for this collection of information is estimated to average .25 hours per response to request a CAGE code, .5 hours per response to request an NCAGE code, and .5 hours per response for ownership reporting. These estimates include time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. The estimates were developed using FY2011 Federal procurement data.
The annual reporting burden to obtain CAGE codes is estimated as follows:
Total CAGE response burden hours: 794 hours.
The annual reporting burden is estimated as follows to respond to ownership provision 52.204–YY requirements:
The combined total of the CAGE hours and the ownership provision hours are 207,698 response burden hours.
Submit comments, including suggestions for reducing this burden, not later than June 17, 2013 to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, Regulatory Secretariat Division (MVCB), ATTN: Hada Flowers, 1275 First Street NE., 7th Floor, Washington, DC 20417.
Public comments are particularly invited on: whether this collection of information is necessary for the proper performance of functions of the FAR, and will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Requesters may obtain a copy of the supporting statement from the General Services Administration, Regulatory Secretariat (MVCB), ATTN: Hada Flowers, 1275 First Street NE., 7th floor, Washington, DC 20417. Please cite OMB Control Number 9000–0185, Commercial and Government Entity Code in all correspondence.
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR parts 4, 12, 22, and 52 as set forth below:
40 U.S.C. 121(c); 10 U.S.C. chapter 137; and 51 U.S.C. 20113.
The added text reads as follows:
(e) 52.204–YY, Ownership or Control of Offeror.
This subpart prescribes policies and procedures for identification of commercial and government entities when it is necessary to—
(a) Exchange data with another contracting activity, including contract administration activities and contract payment activities;
(b) Exchange data with another system that requires the unique identification of a contractor entity; or
(c) Identify when offerors are owned or controlled by another entity.
As used in this part—
(1) An identifier assigned to entities located in the United States and its outlying areas by the Defense Logistics Agency (DLA) Logistics Information Service to identify a commercial or government entity; or
(2) An identifier assigned by a member of the North Atlantic Treaty Organization (NATO) or by NATO's Maintenance and Supply Agency to entities located outside the United States and its outlying areas that DLA Logistics Information Service records and maintains in the CAGE master file. This type of code is known as an NCAGE code.
(a)
(i) A condition listed at 4.605(c)(2) applies; and
(ii) The acquisition is funded by an agency other than DoD or NASA.
(2) The contracting officer shall include the contractor's CAGE code in the contract and in any electronic transmissions of the contract data to other systems, when it is provided in accordance with paragraph (a)(1) of this section.
(b)
(1) A condition listed at 4.605(c)(2) applies; and
(2) The acquisition is funded by an agency other than DoD or NASA.
(a) Contracting officers shall verify the offeror's CAGE code by reviewing the entity's registration in the System for Award Management (SAM). Active registrations in SAM have had the associated CAGE codes verified.
(b) For entities not required to be registered in SAM, the contracting officer shall validate the CAGE code using the CAGE code search feature at
(a) Use the provision at 52.204–XX, Commercial and Government Entity Code Reporting, in all solicitations, except when—
(1) A condition listed at 4.605(c)(2) applies; and
(2) The acquisition is funded by an agency other than DoD or NASA.
(b) Use the provision at 52.204–YY, Ownership or Control of Offeror, in all solicitations, except when—
(1) A condition listed at 4.605(c)(2) applies; and
(2) The acquisition is funded by an agency other than DoD or NASA.
(c) Use the clause at 52.204–ZZ, Commercial and Government Entity Code Maintenance, in all contracts resulting from solicitations containing the provision at 52.204–XX.
(d)
(1) Insert the provision at 52.204–XX, Commercial and Government Entity Code Reporting, as prescribed at 4.1704(a).
(2) Insert the clause at 52.204–ZZ, Commercial and Government Entity Code Maintenance, as prescribed at 4.1704(c).
(3) Insert the clause at 52.225–19, Contractor Personnel in a Designated Operational Area or Supporting a Diplomatic or Consular Mission outside the United States, as prescribed in 25.301–4.
(4) Insert the provision at 52.209–7, Information Regarding Responsibility Matters, as prescribed in 9.104–7(b).
The revised and added text reads as follows:
(c)(2) * * *
___(i) 52.204–YY, Ownership or Control of Offeror. This provision applies to all solicitations above the micro-purchase threshold, except when a condition listed at 4.605(c)(2) applies.
As prescribed in 4.1704(a), use the following provision:
(a)
(1) An identifier assigned to entities located in the United States and its outlying areas by the Defense Logistics Agency (DLA) Logistics Information Service to identify a commercial or government entity, or
(2) An identifier assigned by a member of the North Atlantic Treaty Organization (NATO) or by NATO's Maintenance and Supply Agency (NAMSA) to entities located outside the United States and its outlying areas that DLA Logistics Information Service records and maintains in the CAGE master file. This type of code is known as an NCAGE code.
(b) The offeror shall enter its CAGE code in its offer with its name and address or otherwise include it prominently in its proposal. The CAGE code entered must be for that name and address. Enter “CAGE” before the number. The CAGE code is required prior to award.
(c) CAGE codes may be obtained via—
(1) Registration in the System for Award Management (SAM) at
(2)
(3)
(d) Additional guidance for establishing and maintaining CAGE codes is available at
(e) Do not delay submission of the offer pending receipt of a CAGE code.
As prescribed in 4.1704(b), use the following provision:
(a)
(1) An identifier assigned to entities located in the United States and its outlying areas by the Defense Logistics Agency (DLA) Logistics Information Service to identify a commercial or government entity, or
(2) An identifier assigned by a member of the North Atlantic Treaty Organization (NATO) or by NATO's Maintenance and Supply Agency (NAMSA) to entities located outside the United States and its outlying areas that DLA Logistics Information Service records and maintains in the CAGE master file. This type of code is known as an NCAGE code.
(b) The offeror represents that it [_] is or [_] is not owned or controlled as described in “Owner” definition in paragraph (a) of this provision.
(c) If the offeror has indicated “is” in paragraph (b) of this provision, enter the following information:
Immediate owner is the same as highest-level owner: [_] Yes or [_] No.
(d) If the offeror has indicated “no” in paragraph (c) of this provision, indicating that the immediate owner is not the highest-level owner, then enter the following information:
As prescribed in 4.1704(c), use the following clause:
(a)
(1) An identifier assigned to entities located in the United States and its outlying areas by the Defense Logistics Agency (DLA) Logistics Information Service to identify a commercial or government entity, or
(2) An identifier assigned by a member of the North Atlantic Treaty Organization (NATO) or by NATO's Maintenance and Supply Agency (NAMSA) to entities located outside the United States and its outlying areas that DLA Logistics Information Service records and maintains in the CAGE master file. This type of code is known as an NCAGE code.
(b) Contractors shall ensure that the CAGE code is maintained throughout the life of the contract. For Contractors registered in the System for Award Management (SAM), the DLA Logistics Information Service shall only modify data received from SAM in the CAGE master file if the contractor initiates those changes via update of its SAM registration. Contractors undergoing a novation or change-of-name agreement shall notify the Contracting officer in accordance with subpart 42.12. The Contractor shall communicate any change to the CAGE number to the contracting officer within 30 days after the change, so that a modification can be issued to update the CAGE data on the contract.
(c) Contractors located in the United States or its outlying areas that are not registered in SAM shall submit written change requests to the DLA Logistics Information Service. Requests for changes shall be provided on a DD Form 2051, Request for Assignment of a Commercial and Government Entity (CAGE) Code, to the address shown on the back of the DD Form 2051. Change requests to the CAGE master file are accepted from the entity identified by the code.
(d) Contractors located outside the United States or its outlying areas that are not registered in SAM shall contact the appropriate National Codification Bureau or NAMSA to request CAGE changes. Points of contact for National Codification Bureaus and NAMSA, as well as additional information on obtaining NCAGE codes, are available at
(e) Additional guidance for maintaining CAGE codes is available at to be determined.
The revised and added text reads as follows:
(a) * * *
(b)(1) * * *
(2) The offeror has completed the annual representations and certifications
[Offeror to identify the applicable paragraphs at (c) through (p) of this provision that the offeror has completed for the purposes of this solicitation only, if any.
These amended representation(s) and/or certification(s) are also incorporated in this offer and are current, accurate, and complete as of the date of this offer.
Any changes provided by the offeror are applicable to this solicitation only, and do not result in an update to the representations and certifications posted electronically on SAM.]
(p)
(1) The offeror represents that it [_] is or [_] is not owned or controlled as described in “Owner” definition in paragraph (a) of this provision.
(2) If the offeror has indicated “is” in paragraph (p)(1) of this section, enter the following information:
Immediate owner is the same as highest-level owner: [_] Yes or [_] No.
(3) If the offeror has indicated “no” in paragraph (p)(2) of this section, indicating that the immediate owner is not the highest-level owner, then enter the following information:
National Aeronautics and Space Administration.
Proposed rule.
NASA is updating the NASA FAR Supplement (NFS) with the goal of eliminating unnecessary regulation, streamlining overly burdensome regulation, clarifying language, and simplifying processes where possible. This proposed rule is the first in a series and includes updates and revisions to five NFS parts. On January 18, 2011, President Obama signed Executive Order 13563, Improving Regulations and Regulatory Review, directing agencies to develop a plan for a retrospective analysis of existing regulations. The revisions to this rule are part of NASA's retrospective plan under EO 13563 completed in August 2011.
Interested parties should submit comments to NASA at the address below on or before June 17, 2013 to be considered in formulation of the final rule.
Interested parties may submit comments, identified by RIN number 2700–AE01 via the Federal eRulemaking Portal:
Leigh Pomponio, NASA, Office of Procurement, email:
The NASA FAR Supplement (NFS) is codified at 48 CFR 1800. Periodically, NASA performs a comprehensive review and analysis of the regulation, makes updates and corrections, and reissues the NASA FAR Supplement. The last reissue was in 2004. The goal of the review and analysis is to reduce regulatory burden where justified and appropriate and make the NFS content and processes more efficient and effective, faster and simpler, in support of NASA's mission. Consistent with Executive Order 13563, Improving Regulations and Regulatory Review, NASA is currently reviewing and revising the NFS with an emphasis on streamlining and reducing burden. Due to the volume of the regulation, the revisions to the regulation will be made in increments. This proposed rule is the first of three expected rules which together will constitute the NFS update and reissue. This rule includes revisions to parts 1834, 1841, 1846, 1851, and 1852 of the NFS. Further, this rule provides notice that no regulatory changes will be made to parts 1814, 1815 (exclusive of subpart 1815.4), 1818, 1822, 1824, and 1843.
NASA analyzed the existing regulation to determine whether any portions should be modified, streamlined, expanded, or repealed. Special emphasis was placed on identifying and eliminating or simplifying overly burdensome processes that could be streamlined without jeopardizing Agency mission effectiveness. Additionally, NASA sought to identify current regulatory coverage that is not regulatory in nature, and to remove or relocate such coverage to internal guidance. In addition to substantive changes, this rule includes administrative changes necessary to make minor corrections and updates. Specifically, the changes in this rule are summarized as follows:
1. Administrative changes are made to policy on Earned Value Management System which correct nomenclature and Web site references.
2. In Notice of Earned Value Management System provision at 1852.234–1, a requirement is added for offerors to provide a matrix that correlates each guideline in ANSI/EIA 748 (current version at time of solicitation) to the corresponding process in the offeror's written management procedures; the rule also updates Web site and references in the provision.
3. In Earned Value Management System clause at 1852.234–2, administrative changes are made to correct nomenclature and add a Web site reference.
1. Subpart 1846.6—Material Inspection and Receiving Reports, is revised to align with DFAR Appendix F, facilitating comparison of NASA and DoD practices and procedures with regard to DD Form 250, especially for contractors doing business with both agencies. Administrative changes are also made to this subpart to clarify DD Form 250 preparation instructions.
2. The clause 1852.246–72, Material Inspection and Receiving Report, is revised slightly to clarify distribution requirements.
Executive Orders (E.O.s) 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule is not a “significant regulatory action” under section 3(f) of Executive Order 12866. This rule is not a major rule under 5 U.S.C. 804.
NASA certifies that this proposed rule will not have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601
The proposed rule contains a new information collection requirement that requires the approval of the Office of Management and Budget under the Paperwork Reduction Act (44 U.S.C. Chapter 35). The collection is at 1852.215–77(c), Pre-proposal/pre-bid conference, wherein attendees at pre-proposal or pre-bid conferences will be required to submit personal identity information. NASA invites public comments on the following aspects of the proposed rule: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of NASA, including whether the information will have practical utility; (b) the accuracy of the estimate of the burden of the proposed information collection; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the information collection on respondents, including the use of automated collection techniques or other forms of information technology. The following is a summary of the information collection requirement.
Written comments and recommendations on the proposed information collection should be sent to NASA, Attn:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to NASA, Attn: Leigh Pomponio, 300 E Street SW., Washington, DC 20546–0001.
Government procurement.
Accordingly, 48 CFR parts 1834, 1841, 1846, 1851, and 1852 are proposed to be amended as follows:
42 U.S.C. 2473(c)(1).
The addition reads as follows:
(f) As a minimum, and in accordance with NPD 7120.5, requirements initiators shall ensure that EVMS monthly reports are included as a deliverable in the acquisition package provided to the procurement office for implementation into contracts where EVMS applies. Additionally, the acquisition package shall include a Contract Performance Report (CPR), IMS and a Work Breakdown Structure (WBS) and the appropriate data requirements descriptions (DRDs) for implementation into the contract.
42 U.S.C. 2473(c)(1).
U.S.C. 2473(c)(1).
“Counterfeit goods” means an item that is an unauthorized copy or substitute that has been identified, marked, and/or altered by a source other than the item's legally authorized source and has been misrepresented to be an authorized item of the legally authorized source.
“Legally authorized source” means the current design activity or the original manufacturer or a supplier authorized by the current design activity or the original manufacturer to produce an item.
(f) See NPR 8735.2, Section 2.1, concerning quality assurance for critical acquisition items. Generally, the quality assurance requirements set forth in the NPR for critical acquisition items are not allowed under Part 12 procedures. See FAR 12.208.
This subpart contains procedures and instructions for use of the DD Form 250, Material Inspection and Receiving Report (MIRR), (DD Form 250 series equivalents, and commercial shipping/packing lists used to document Government contract quality assurance (CQA).
(a) This subpart applies to supplies or services acquired by or for NASA when the clause at 1852.246–72, Material Inspection and Receiving Report, is included in the contract.
(a) The DD Form 250 is a multipurpose report used for—
(1) Providing evidence of CQA at origin or destination;
(2) Providing evidence of acceptance at origin or destination;
(3) Packing lists;
(4) Receiving;
(5) Shipping; and
(6) Contractor invoice support.
(b) Do not use MIRRs for shipments—
(1) By subcontractors, unless the subcontractor is shipping directly to the Government; or,
(2) Of contract inventory.
(c) The contractor prepares the DD Form 250, except for entries that an authorized Government representative is required to complete. The contractor shall furnish sufficient copies of the completed form, as directed by the Government Representative.
An electronic copy of the DD Form 250 may be downloaded from the General Services Administration's Forms Library at
(1) Dates shall include nine spaces consisting of the four digits of the year, the first three letters of the month, and two digits for the date (e.g., 2012SEP24).
(b)
(c)
(h)
The contractor may enter the invoice number and actual or estimated date on all copies of the MIRR. When the date is estimated, enter an “E” after the date. Do not correct MIRRs to reflect the actual date of invoice submission.
* * *
(j)
(k)
* * *
In section 1846.672, the first sentence of paragraph (r)(1)(i) is amended by removing the phrase “Federal” and adding its place the phrase “national” and removing the phrase “(FSN)” and adding in its place the phrase “(NSN)”.
j. In section 1846.672, paragraph (r)(3) is revised by replacing “Command” with “Agency”.
k. In section 1846.672, paragraph (r)(4)(ii) is revised by replacing “FSN” with “NSN”.
l. In section 1846.672, paragraph (r)(4)(v) is revised by replacing “FSN” with “NSN”.
m. In section 1846.672, paragraph (r)(4)(xi) is revised by replacing “shall” with “will”.
Sections 1846.672–6 and 1846.672–7 are redesignated as 1846.672–5 and 1846.672–6.
The contracting officer shall insert the clause at 1852.246–72, Material Inspection and Receiving Report, in solicitations and contracts when there will be separate and distinct deliverables, even if the deliverables are not separately priced. The clause is not required for—
(1) Contracts awarded using simplified acquisition procedures;
(2) Negotiated subsistence contracts; or
(3) Contracts for which the deliverable is a scientific or technical report. Insert number of copies and distribution instructions in paragraph (a).
42 U.S.C. 2473(c)(1).
42 U.S.C. 2473(c)(1).
(c) Offerors, individuals, or interested parties who plan to attend the pre-proposal/pre-bid conference must provide the Contracting Officer in writing, at a minimum, full name of the attendee(s), identification of nationality (U.S. or specify other nation citizenship), Lawful Permanent Resident Numbers in the case of foreign nationals, affiliation and full office address/phone number. Center-specific security requirements for this pre-proposal/pre-bid conference will be given to a company representative prior to the conference or will be identified in this solicitation as follows: (
(d) Visitors on NASA Centers are allowed to possess and use photographic equipment (including camera cell phones) and related materials EXCEPT IN CONTROLLED AREAS. Anyone desiring to use camera equipment during the conference should contact the Contracting Officer to determine if the site(s) to be visited is a controlled area.
(e) The Government will respond to questions regarding this procurement provided such questions have been received at least five (5) working days prior to the conference. Other questions will be answered at the conference or in writing at a later time. All questions, together with the Government's response, will be transmitted to all solicitation recipients via the government-wide point of entry (GPE). In addition, conference materials distributed at the preproposal/pre-bid conference will be made available to all potential offerors via the GPE using the NAIS Electronic Posting System.
The revisions read as follows:
(a) * * *
(b) * * * Other limitations/instructions identified as follows: (
(c) Identify any exclusions to the page limits that are excluded from the page counts specified in paragraph (a) of this provision (e.g. title pages, table of contents) as follows: (
The revisions read as follows:
(b) * * *
(1) * * *
(iii) Provide a matrix that correlates each guideline in ANSI/EIA 748 (current version at time of solicitation) to the corresponding process in the offeror's written management procedures;
(vii) If the value of the offeror's proposal, including options, is $50 million or more, provide a schedule of events leading up to formal validation and Government acceptance of the Contractor's EVMS. Guidance can be found in the Department of Defense Earned Value Management Implementation Guide (
The revisions read as follows:
(a) * * *
(2) Earned Value Management (EVM) procedures that provide for generation of timely, accurate, reliable, and traceable information for the Contract Performance Report (CPR) and the Integrated Master Schedule (IMS) required by the data requirements descriptions in the contract.
(a) At the time of each delivery to the Government under this contract, the Contractor shall prepare and furnish a Material Inspection and Receiving Report (DD Form 250 series). The form(s) shall be prepared and distributed as follows:
(Insert number of copies and distribution instructions.)
United States Agency for International Development.
Altered system of records.
The United States Agency for International Development (USAID) is issuing public notice of its intent to alter a system of records maintained in accordance with the Privacy Act of 1974 (5 U.S.C. 552a), as amended, entitled “USAID–09, Criminal Law Enforcement Records System”. USAID is updating this system of record for a non-significant change, to reflect the address change for the location of the system. This action is necessary to meet the requirements of the Privacy Act to publish in the
The 30-day public comment period and 10-day additional OMB and Congress review period is not required for non-significant alterations.
You may submit comments:
•
•
•
•
For general questions, please contact, USAID Privacy Office, United States Agency for International Development, 2733 Crystal Drive, 11th Floor, Arlington, VA 22202. Email:
The Criminal Law Enforcement Records System, will now be electronically stored and located in a new location. The new location is: Terremark NAP of the Americas, 2 S Biscayne Blvd., Miami, FL 33131.
Criminal Law Enforcement Records System
Sensitive But Unclassified.
Terremark NAP of the Americas, 2 S Biscayne Blvd., Miami, FL 33131.
In connection with its investigative duties, OIG maintains records in its Criminal law Enforcement Records System on the following categories of individuals insofar as they are relevant to any investigation or preliminary inquiry undertaken to determine whether to commence an investigation: complainants; witnesses; confidential and non-confidential informants; contractors; subcontractors; recipients of federal assistance or funds and their contractors/subcontractors and employees; individuals threatening USAID employees or the USAID Administrator; current, former, and prospective employees of USAID; alleged violators of USAID rules and regulations; union officials; individuals investigated and/or interviewed; persons suspected of violations of administrative, civil, and/or criminal provisions; grantees,' sub-grantees; lessees; licensees; and other persons engaged in official business with USAID.
The system contains investigative reports and materials gathered or created with regard to investigations of administrative, civil, and criminal matters by OIG and other Federal, State, local, tribal, territorial, or foreign regulatory or law enforcement agencies. Categories of records may include: complaints; request to investigate; information contained in criminal, civil, or administrative referrals; statements from subjects, targets, and/or witnesses; affidavits, transcripts, police reports, photographs, and/or documents relative to a subject's prior criminal record; medical records, accident reports, materials and intelligence information from other governmental investigatory or law enforcement organizations; information relative to the status of a particular complaint or investigation, including any determination relative to criminal prosecution, civil, or administrative action; general case management documentation' subpoenas and evidence obtained in response to subpoenas; evidence logs; pen registers; correspondence, records of seized property' reports of laboratory examination; reports of investigation; and other data or evidence collected or generated by OIG's Office of Investigations during the course of conducting its official duties.
The Inspector General Act of 1978, 5 U.S.C. App. 3, as amended.
The records contained in this system are used by OIG to carry out its statutory responsibilities under the Inspector General Act of 1978, as amended, to conduct and supervise investigations relating to programs and operations of USAID; to promote economy, efficiency, and effectiveness in the administration of such programs and operations; and to prevent and detect fraud, waste, and abuse in such programs and operations. The records are used in the course of investigating individuals and entities suspected of having committed illegal or unethical acts, and in conducting related criminal prosecutions, civil proceedings, and administrative actions.
USAID's routine uses, see 42 FR 47371 (September 20, 1977) and 59 FR 52954 (October 20, 1994), apply to this system of records. As additional routine uses for this records system, USAID/OIG may disclose information in this system as follows:
(a) Disclosure to the Department of Justice (DOJ) or a legal representative designated by a Federal Agency in circumstances in which:
(1) USAID or OIG, or any component thereof:
(2) Any employee of USAID or OIG in his or her official capacity;
(3) Any employee of USAID or OIG in his or her individual capacity, where the DOJ has agreed to represent or is considering a request to represent the employee; or
(4) The United States or any of its components is a party to pending or potential litigation or has an interest in such litigation, USAID or OIG will be affected by the litigation, or USAID or OIG determines that the use of such records by the DOJ is relevant and necessary to the litigation; provided, however, that in each case, USAID or OIG determines that disclosure of the records to the DOJ is a use of the information that is compatible with the purpose for which the records were collected.
(b) Disclosure to any source from which additional information is requested in order to obtain information relevant to:
(1) A decision by either USAID or OIG concerning the hiring, assignment, or retention of an individual or other personnel action;
(2) The issuance, renewal, retention, or revocation of a security clearance;
(3) The execution of a security or suitability investigation;
(4) The letting of a contract; or
(5) The issuance, retention, or revocation of a license, grant, award, contract, or other benefit to the extent the information is relevant and necessary to a decision by USAID or OIG on the matter.
(c) Disclosure to a Federal, State, local, foreign, tribal, territorial, or other public authority in response to its request in connection with:
(1) The hiring, assignment, or retention, of an individual;
(2) The issuance, renewal, retention or revocation of a security clearance;
(3) The execution of a security or suitability investigation;
(4) The letting of a contract; or
(5) The issuance, retention, or revocation of a license, grant, award, contract, or other benefit conferred by that entity to the extent that the information is relevant and necessary to the requesting entity's decision on the matter.
(d) Disclosure in the event that a record, either by itself or in combination with other information, indicates a violation or a potential violation of law, whether civil, criminal, or regulatory in nature, and whether arising by general statute or particular program stature, or by regulation, rule, or order issued pursuant thereto; or a violation or potential violation of a contract provision. In these circumstances, the relevant records in the system may be referred, as a routine use, to the appropriate entity, whether Federal, State, tribal, territorial, local or foreign, charged with the responsibility of investigating or prosecuting such violation or charged with enforcing or implementing the statute, rule, regulation, order or contract.
(e) Disclosure to any source from which additional information is requested, either private or governmental, to the extent necessary to solicit information relevant to any investigation, audit, or evaluation.
(f) Disclosure to a foreign government pursuant to an international treaty, convention, or executive agreement entered into by the United States.
(g) Disclosure to contractors, grantees, consultants, or volunteers performing or working on a contract, service, grant, cooperative agreement, job or other activity for USAID or OIG, who have a need to access the information in the performance of their duties or activities. When appropriate, recipients will be required to comply with the requirements of the Privacy Act of 1974 as provided in 5 U.S.C. 552a(m).
(h) Disclosure to representatives of the Office of Personnel Management, the Office of Special Counsel, the Merit Systems Protection Board, the Federal Labor Relations Authority, the Equal Employment Opportunity Commission, the Office of Government Ethics, and other Federal agencies in connection with their efforts to carry out their responsibilities to conduct examinations, investigations, and/or settlement efforts, in connection with administrative grievances, complaints, claims, or appeals filed by an employee, and such other functions promulgated in 5 U.S.C. 1205–06.
(i) Disclosure to a grand jury agent pursuant to a Federal or State grand jury subpoena or to a prosecution request that such record be released for the purpose of its introduction to a grand jury.
(j) Disclosure in response to a facially valid subpoena for the record.
(k) Disclosure to the National Archives and Records Administration for the purpose of records management inspections conducted under authority of 44 U.S.C. 2904, 2906.
(l) Disclosure to the Departments of the Treasury and Justice in circumstances in which OIG seeks to obtain, or has in fact obtained, and ex parte court order to obtain tax return information from the Internal Revenue Service.
(m) Disclosure to any Federal official charged with the responsibility to conduct qualitative assessment reviews of internal safeguards and management procedures employed in investigative operations for purposed of reporting to the President and Congress on the activities of OIF as contemplated by the Homeland Security Act of 2002 (Pub. L. 107–296; November 25, 2002). This disclosure category includes other Federal offices of inspectors general and members of the President's Council on Integrity and Efficiency, and officials and administrative staff within their investigative chain of command, as well as authorized officials of DOJ and its component, the Federal Bureau of Investigation.
Not applicable.
Paper records and all other media (photographs, audio recordings, diskettes, CD's etc) are stored in GSA-approved security containers with combination locks in a secured area. Electronic records are password protected and maintained on a file server in locked facilities that are secured at all times by security systems and video surveillance cameras.
Records are retrieved in a database by name and or alias, as well as by non-personally identifiable information, such as case number.
Access to paper records is restricted to authorized OIG employees on a need-to-know basis. At all times, paper records are maintained in locked safes in a secured area in offices that are occupied by authorized OIG employees. Access to electronic records is restricted to authorized OIG staff members on a need-to-know basis. Each person granted access to the system must be individually authorized to use the system.
Disclosure of records maintained electronically is restricted through the use of passwords. The computer servers in which records are stored are password protected. Passwords are changed on a cyclical basis. The computer servers are located in locked facilities that are secured at all times by
Records relating to persons covered by this system are retained for two or five years after the investigation is closed. If an investigation does not involve allegations against a senior level USAID employee, is not of congressional interest, or does not yield a reportable result, the records within the closed case file are maintained for a period of two years from the date of closing by OIG. If the investigation yields a reportable result, has congressional interest, or involves allegations against a senior level USAID employee, the records within the closed case file will be retained for five years from the date of closing by OIG. After the applicable period (two or five years), closed investigative files will be sent from USAID, Office of Inspector General, 1300 Pennsylvania Ave. NW., Washington, DC 20523, to the Washington National Records Center in Suitland, Maryland, where they will be retained for fifteen years, and subsequently destroyed. Any electronic file that qualifies as a record will be printed out and treated as a hard-copy record for disposition purposes.
Records in this system are exempt from notification, access, and amendment procedure in accordance with subsections (j) and (k) of 5 U.S.C. 552a, and 22 CFR 215.13 and 215.14. Individuals requesting notification of the existence of records on themselves should send their request to the System Manager (see information above). The request must be in writing and include the requester's full name, his or her current address, his or her date and place of birth, and a return address for transmitting the information. The request shall be signed by either notarized signature or by signature under penalty of perjury. Requesters shall also reasonably specify the record contents being sought.
Individuals wishing to request access to a record on himself or herself must submit the request in writing according to the “Notification Procedures” above.
An individual requesting amendment of a record maintained on himself or herself must identify the information to be changed and the corrective action sought. Requests must follow the “Notification Procedures” above.
OIG collects information from a wide variety of sources, including information from USAID and other Federal, State and local agencies, subjects, witnesses, complainants, confidential and/or non-confidential sources, and other nongovernmental entities.
Under the specific authority provided by subsection (j)(2) of 5 U.S.C. 552a, USAID has adopted regulations, 22 CFR 215.13 and 215.14, which exempt this system from the notice, access, and amendment requirements of 5 U.S.C. 552a, except subsections (b); (c)(1) and (2); (e)(4)(A) through (F); (e)(6), (7), (9), (10), and (11); and (i). If the provision found at subsection (j)(2) of 5 U.S.C. 552a is held to be invalid, then, under subsections (k)(1) and (2) of 5 U.S.C. 552a, this system is determined to be exempt from the provisions of subsections (c)(3); (d); (e)(1); (e)(4)(G), (H), and (I); and (f) of 5 U.S.C. 552a. See 57 FR 38276, 38280–81 (August 24, 1992). The reasons for adoption of 22 CFR 215.13 and 215.14 are to protect the materials required by Executive order to be kept secret in the interest of national defense of foreign policy, to maintain the integrity of the law enforcement process, to ensure the proper functioning and integrity of law enforcement activities, to prevent disclosures of investigative techniques, to maintain the ability to obtain necessary information, to prevent subjects of investigation from frustrating the investigatory process, to avoid premature disclosure of the knowledge of criminal activity and the evidentiary basis of possible enforcement actions, to fulfill commitments made to sources to protect their identities and the confidentiality of information, and to avoid endangering these sources and law enforcement personnel.
Office of Tribal Relations, USDA.
Notice of public meeting.
This notice announces a forthcoming meeting of The Council for Native American Farming and Ranching (CNAFR) a public advisory committee of the Office of Tribal Relations (OTR). Notice of the meetings are provided in accordance with section 10(a)(2) of the Federal Advisory Committee Act, as amended, (5 U.S.C. Appendix 2). This will be the third meeting of the CNAFR and will consist of, but not limited to: hearing public comments; update of USDA programs and activities; discussion of committee priorities. This meeting will be open to the public.
The meeting will be held on May 3, 2013 from 1 p.m. to 5 p.m. EST. The meeting will be open to the public. Note that a period for public comment will be held on May 3, 2013 4:00 p.m. to 5:00 p.m. EST
The meeting will be conducted using webinar and teleconference technology. This will not be an in-person meeting. Webinar and teleconference access information for the meeting will be posted to the OTR Web site at
Questions should be directed to John Lowery, Tribal Relations Manager, OTR, 1400 Independence Ave. SW., Whitten Bldg., 500A, Washington, DC 20250; by Fax: (202) 720–1058 or email:
In accordance with the provisions of the Federal Advisory Committee Act (FACA) as amended (5 U.S.C. App. 2), USDA established an advisory council for Native American farmers and ranchers. The CNAFR is a discretionary advisory committee established under the authority of the Secretary of Agriculture, in furtherance of the settlement agreement in
The CNAFR will operate under the provisions of the FACA and report to the Secretary of Agriculture. The purpose of the CNAFR is (1) to advise the Secretary of Agriculture on issues related to the participation of Native American farmers and ranchers in USDA farm loan programs; (2) to transmit recommendations concerning any changes to FSA regulations or internal guidance or other measures that would eliminate barriers to program participation for Native American farmers and ranchers; (3) to examine methods of maximizing the number of new farming and ranching opportunities created through the farm loan program through enhanced extension and financial literacy services; (4) to examine methods of encouraging intergovernmental cooperation to mitigate the effects of land tenure and probate issues on the delivery of USDA farm loan programs; (5) to evaluate other methods of creating new farming or ranching opportunities for Native American producers; and (6) to address other related issues as deemed appropriate.
The Secretary of Agriculture selected a diverse group of members representing a broad spectrum of persons interested in providing solutions to the challenges of the aforementioned purposes. Equal opportunity practices were considered in all appointments to the CNAFR in accordance with USDA policies. The Secretary selected the members in May 2012. Interested persons may present views, orally or in writing, on issues relating to agenda topics before the CNAFR.
Written submissions may be submitted to the contact person on or before April 26, 2013. Oral presentations from the public will be scheduled between approximately 4:00 p.m. to 5:00 p.m. on May 3, 2013. Those individuals interested in making formal oral presentations should notify the contact person and submit a brief statement of the general nature of the issue they wish to present and the names and addresses of proposed participants by April 26, 2013. All oral presentations will be given three (3) to five (5) minutes depending on the number of participants.
OTR will also make all agenda topics available to the public via the OTR Web site:
Animal and Plant Health Inspection Service, USDA.
Notice of availability.
We are advising the public that the Animal and Plant Health Inspection Service has prepared an environmental assessment concerning authorization to ship for the purpose of field testing, and then to field test, an unlicensed Yersinia Pestis Vaccine, Live Raccoon Poxvirus Vector. The environmental assessment, which is based on a risk analysis prepared to assess the risks associated with the field testing of this vaccine and related information, examines the potential effects that field testing this veterinary vaccine could have on the quality of the human environment. Based on the risk analysis and other relevant data, we have reached a preliminary determination that field testing this veterinary vaccine will not have a significant impact on the quality of the human environment, and that an environmental impact statement need not be prepared. We intend to authorize shipment of this vaccine for field testing following the close of the comment period for this notice unless new substantial issues bearing on the effects of this action are brought to our attention. We also intend to issue a U.S. Veterinary Biological Product license for this vaccine, provided the field test data support the conclusions of the environmental assessment and the issuance of a finding of no significant impact and the product meets all other requirements for licensing.
We will consider all comments that we receive on or before May 20, 2013.
You may submit comments by either of the following methods:
•
•
Supporting documents and any comments we receive on this docket may be viewed at
Dr. Donna Malloy, Operational Support Section, Center for Veterinary Biologics, Policy, Evaluation, and Licensing, VS, APHIS, 4700 River Road Unit 148, Riverdale, MD 20737–1231; phone (301) 851–3426, fax (301) 734–4314.
For information regarding the environmental assessment or the risk analysis, or to request a copy of the environmental assessment (as well as the risk analysis with confidential business information removed), contact Dr. Patricia L. Foley, Risk Manager, Center for Veterinary Biologics, Policy, Evaluation, and Licensing VS, APHIS, 1920 Dayton Avenue, P.O. Box 844, Ames, IA 50010; phone (515) 337–6100, fax (515) 337–6120.
Under the Virus-Serum-Toxin Act (21 U.S.C. 151
To determine whether to authorize shipment and grant approval for the field testing of the unlicensed product referenced in this notice, APHIS considers the potential effects of this product on the safety of animals, public health, and the environment. Using the
The above-mentioned product consists of a live recombinant raccoon poxvirus vector expressing two
The EA has been prepared in accordance with: (1) The National Environmental Policy Act of 1969 (NEPA), as amended (42 U.S.C. 4321
Unless substantial issues with adverse environmental impacts are raised in response to this notice, APHIS intends to issue a finding of no significant impact (FONSI) based on the EA and authorize shipment of the above product for the initiation of field tests following the close of the comment period for this notice.
Because the issues raised by field testing and by issuance of a license are identical, APHIS has concluded that the EA that is generated for field testing would also be applicable to the proposed licensing action. Provided that the field test data support the conclusions of the original EA and the issuance of a FONSI, APHIS does not intend to issue a separate EA and FONSI to support the issuance of the product license, and would determine that an environmental impact statement need not be prepared. APHIS intends to issue a veterinary biological product license for this vaccine following completion of the field test provided no adverse impacts on the human environment are identified and provided the product meets all other requirements for licensing.
21 U.S.C. 151–159.
Animal and Plant Health Inspection Service, USDA.
Notice of availability.
We are advising the public that we have prepared a pest list associated with oranges and tangerines from Egypt that identifies pests of concern. Subsequently, we prepared a commodity import evaluation document to determine the risk posed by peach fruit fly in oranges and tangerines from Egypt. Based on that evaluation, we have concluded that the application of one or more designated phytosanitary measures will be sufficient to mitigate the pest risk. In addition, we are advising the public that we have prepared a treatment evaluation document that describes a new treatment schedule that can be used to neutralize peach fruit fly and Mediterranean fruit fly in oranges and tangerines. We are making the pest list, commodity import evaluation document, and treatment evaluation document available to the public for review and comment.
We will consider all comments that we receive on or before June 17, 2013.
You may submit comments by either of the following methods:
•
•
Supporting documents and any comments we receive on this docket may be viewed at
Mr. Tony Romàn, Import Specialist, PPQ, APHIS, 4700 River Road Unit 156, Riverdale, MD 20737; (301) 851–2242.
Under the regulations in “Subpart–Fruits and Vegetables” (7 CFR 319.56–1 through 319.56–58), the Animal and Plant Health Inspection Service (APHIS) prohibits or restricts the importation of fruits and vegetables into the United States from certain parts of the world to prevent the introduction and dissemination of plant pests that are new to or not widely distributed within the United States.
Section 319.56–4 contains a performance-based process for approving the importation of commodities that, based on the findings of a pest risk analysis, can be safely imported subject to one or more of the designated phytosanitary measures listed in paragraph (b) of that section.
Oranges (
Because of the time that had passed since importation of oranges from Egypt was suspended, APHIS prepared a pest list to identify pests of quarantine significance that could follow the pathway of importation of oranges and tangerines from Egypt. Based on the pest list, we then completed a commodity import evaluation document (CIED) to identify phytosanitary measures that could be applied to mitigate the risks of introducing or disseminating the identified pests via the importation of
• The oranges and tangerines must be treated in accordance with 7 CFR part 305 for
• The oranges and tangerines must be accompanied by a phytosanitary certificate issued by the NPPO of Egypt stating that the consignment has begun or has undergone treatment for
Therefore, in accordance with § 319.56–4(c), we are announcing the availability of our pest list and CIED for public review and comment. The pest list and CIED may be viewed on the Regulations.gov Web site or in our reading room (see
After reviewing any comments we receive, we will announce our decision regarding the import status of fresh oranges and tangerines from Egypt in a subsequent notice. If the overall conclusions of the analysis and the Administrator's determination of risk remain unchanged following our consideration of the comments, then we will authorize the importation of fresh oranges and tangerines from Egypt into the United States subject to the requirements specified in the CIED.
The phytosanitary treatments regulations contained in part 305 of 7 CFR chapter III set out standards for treatments required in parts 301, 318, and 319 of 7 CFR chapter III for fruits, vegetables, and other articles.
In § 305.2, paragraph (b) states that approved treatment schedules are set out in the Plant Protection and Quarantine (PPQ) Treatment Manual.
The PPQ Treatment Manual does not currently provide a treatment schedule for
In addition to
The reasons for these determinations are described in a treatment evaluation document (TED) we have prepared to support this action. The TED may be viewed on the Regulations.gov Web site or in our reading room. You may also request paper copies of the TED by calling or writing to the person listed under
After reviewing the comments we receive, we will announce our decision regarding the changes to the PPQ Treatment Manual that are described in the TED in a subsequent notice. If our determination that it is necessary to add new treatment schedule T107–1 remains unchanged following our consideration of the comments, then we will make available a new version of the PPQ Treatment Manual that reflects the addition of T107–l.
7 U.S.C. 450, 7701–7772, and 7781–7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Animal and Plant Health Inspection Service, USDA.
Notice.
We are advising the public that we are adding 31 taxa of plants for planting that are quarantine pests and 107 taxa of plants for planting that are hosts of 13 quarantine pests to our lists of taxa of plants for planting whose importation is not authorized pending pest risk analysis. A previous notice made data sheets that detailed the scientific evidence we evaluated in making the determination that the taxa are quarantine pests or hosts of quarantine pests available to the public for review and comment. This notice responds to the comments we received and makes available final versions of the data sheets, with changes in response to comments.
Dr. Arnold Tschanz, Senior Regulatory Policy Specialist, Plants for Planting Policy, RPM, PPQ, APHIS, 4700 River Road Unit 133, Riverdale, MD 20737–1236; (301) 851–2018.
Under the regulations in “Subpart—Plants for Planting” (7 CFR 319.37 through 319.37–14, referred to below as the regulations), the Animal and Plant Health Inspection Service (APHIS) of the U.S. Department of Agriculture (USDA) prohibits or restricts the importation of plants for planting (including living plants, plant parts, seeds, and plant cuttings) to prevent the introduction of quarantine pests into the United States.
In a final rule published in the
Paragraph (b) of § 319.37–2a describes the process for adding taxa to the NAPPRA lists. In accordance with that process, we published a notice
We solicited comments concerning the notice and the data sheets for 60 days ending September 26, 2011. We reopened and extended the deadline for comments until November 25, 2011, in a document published in the
The July 26, 2011, notice indicated that we would consider comments and announce whether the taxa identified in the data sheets would be added to the NAPPRA lists in a subsequent notice.
One commenter stated that, due to the risk of importing quarantine pests after the initial notice is published, plants that we determine to be quarantine pests or hosts of quarantine pests should be added to the NAPPRA list at the same time as we publish the notice making available the data sheets supporting that determination. The notice could have a public comment period allowing for changes to the initial list of taxa.
Another commenter disagreed, stating that APHIS must often make regulatory decisions on the basis of incomplete information, and a reasonable comment period prior to action allows other interested parties the opportunity to present valid information and perspectives that will help APHIS to “get it right.” This commenter stated that APHIS always has the ability to issue emergency prohibitions or restrictions, should the situation warrant them.
We agree with the second commenter. As described in the May 2011 final rule establishing the NAPPRA category, when we find evidence that the importation of a taxon of plants for planting that is currently being imported poses a risk of introducing a quarantine pest, we restrict or prohibit its importation through the issuance of a Federal import quarantine order, also referred to as a Federal order. For other taxa, we will issue a notice through the NAPPRA process.
One commenter expressed concern that the 60-day comment period on the initial notice and subsequent decisionmaking period may create something of a “gold rush” effect in which importers are forewarned to import numerous specimens of risky species before APHIS blocks further imports. The commenter stated that the May 2011 final rule did not fully address this risk. The commenter recommended we address this risk by making liberal use of immediate prohibition orders for the riskiest species, such as was done in the May 30, 2008, Federal order that prohibited imports of
We will issue a Federal order prohibiting the importation of a taxon of plants for planting that is currently being imported whenever we determine it to be necessary to prevent the introduction of a quarantine pest. We will also strive to ensure that we complete our decisionmaking quickly after the comment period has ended. However, we will continue to monitor imports of taxa that we have proposed to add to NAPPRA; if a “gold rush” effect occurs for any of them, we have the option to issue a Federal order.
One commenter asked about the relationship between Federal orders and the NAPPRA category. The commenter perceived some inconsistencies. For example:
• Exemptions for specific host plant material types (e.g., plant size, cuttings, etc.) outlined in Federal orders are inconsistent with NAPPRA.
• Exemptions for specific origins (i.e., pest not present/known to occur in specified origin) outlined in Federal orders are inconsistent with NAPPRA.
The importation of taxa that are hosts of several of the quarantine pests described in our data sheets has been subject to Federal orders. In the July 2011 notice, we took comment on their addition to the NAPPRA category. This is consistent with our overall plan for the relationship between Federal orders and NAPPRA.
If a taxon of plants for planting is currently being imported and we determine that the taxon should be added to the NAPPRA category because it is a host of a quarantine pest, we will issue a Federal order to restrict or prohibit its importation. We will also publish a notice announcing our determination that the taxon is a host of a quarantine pest and making available a data sheet that details the scientific evidence that we evaluated in making our determination, including references for that scientific evidence. We will solicit comments from the public. If comments present information that leads us to determine that the importation of the taxon does not pose a risk of introducing a quarantine pest into the United States, APHIS will rescind the Federal order and not add the taxon to the NAPPRA list.
As noted in the July 2011 notice, in a few cases, taxa that are listed as NAPPRA from most countries will be allowed to be imported from countries that are currently exporting the taxa to the United States, subject to restrictions in a Federal order that was issued previously. We would continue to allow such importation based on our experience with importing those taxa of plants for planting and our findings, through inspection, that they are generally pest-free, and based on our determination that the restrictions in the Federal order are sufficient to mitigate the risk associated with the quarantine pest in question. Each data sheet we made available with the July 2011 notice included an “Action under NAPPRA” section describing the specific taxa and countries that would be added to NAPPRA. These sections
With respect to host plant material types, the NAPPRA category does not allow for exceptions for host material types except for seed. Plant type-specific restrictions are discussed further later in this document under the heading “Hosts of Quarantine Pests.”
With respect to the origin of imports, the Federal order is specifically designed to address current trade; the NAPPRA category is designed to prevent the importation of a taxon from anywhere in the world until we can conduct a pest risk analysis (PRA) to determine what risks may be associated with the importation of the taxon and what means may be available to mitigate those risks.
The commenter also asked how we will ensure cohesion and consistency between the Federal orders and the NAPPRA list of plants, e.g., will the Federal orders be updated to reflect the new NAPPRA list.
If a taxon of plants for planting is on the NAPPRA list for a given country, we would no longer need to include it in a Federal order for that country, and would update the Federal order accordingly. We are doing just that with the pests that have been subject to Federal orders and that are being addressed by this action. The updated Federal orders will note that the importation of the taxa from some countries is not allowed under NAPPRA.
Some commenters suggested pests for consideration for future addition to the NAPPRA lists. We are considering those taxa for addition to NAPPRA. Interested members of the public can also submit suggestions for additions to the NAPPRA lists at
One commenter described the goal of the NAPPRA category as responding more swiftly and effectively to prevent the introduction of specific quarantine pests from established trading partners. In that case, the commenter stated, APHIS should be prepared to remove a plant taxon from NAPPRA if presented with a mitigation proposal that addresses the quarantine pest(s) for which APHIS justified the NAPPRA listing in the first place.
The commenter urged APHIS to concurrently implement two other components of the overhaul of our regulations on the importation of plants for planting. First, APHIS should overhaul the permit system to allow for swift, legal importation of limited quantities of germplasm that is restricted under NAPPRA for research, development, and new variety introduction, subject to appropriate safeguards and oversight.
Secondly, the commenter urged APHIS to establish the regulatory framework for implementing integrated measures programs, widely known and referred to as systems approaches. The commenter stated that integrated measures approaches offer the promise of mitigating the risk of various pests of regulatory concern, and, as NAPPRA is implemented, such approaches can and should serve as a mechanism for facilitating trade in plants that may be restricted under NAPPRA as hosts of quarantine pests. The commenter also stated that implementation of those systems approaches should not necessarily require a full PRA, although in some cases it may.
The commenter expressed concern that restriction of horticulturally significant plant taxa under NAPPRA without concurrent attention to the controlled import permit (CIP) and integrated measures regulatory strategies will discourage compliant trade and encourage unauthorized importation and could also subject APHIS to challenge under international trade agreements. By contrast, concurrent implementation of those rules could address the concerns one commenter expressed that proposals to restrict plants as NAPPRA may create something of a “gold rush mentality” in which various interests rush to import them in advance of restrictions taking effect.
We agree with the commenter regarding the importance of these regulatory strategies. As the commenter noted, we published a proposed rule to establish CIPs in the
We are also developing a proposed rule to reorganize the plants for planting regulations and to establish a framework for integrated measures programs. The framework will be based on Regional Standard for Phytosanitary Measures (RSPM) No. 24
We are adding taxa to the NAPPRA category before finalizing the CIP proposal and the integrated measures proposal because it is necessary to protect U.S. agricultural and environmental resources against the introduction of the quarantine pests identified and described in our data sheets. However, it is our intention that the two rules will provide increased flexibility to safely import NAPPRA-listed taxa in the manner the commenter describes. In the meantime, limited quantities of plant taxa on the NAPPRA lists may be imported by the USDA for experimental or scientific purposes under controlled conditions in accordance with the Departmental permit provisions in § 319.37–2(c).
We would also like to note that the goal of the NAPPRA category is not to respond to specific quarantine pest risks from established trading partners, but rather to prevent the importation of taxa that are quarantine pests or hosts of quarantine pests while a PRA is conducted to determine all the quarantine pests associated with the taxon and, if available, appropriate mitigations. As described earlier, when we find evidence that the importation of taxa of plants for planting that are currently being imported poses a risk of introducing a quarantine pest, we prohibit or restrict their importation through the issuance of a Federal order. The Federal order for such taxa may be followed by a NAPPRA notice for the countries from which the taxa are imported if no mitigations are available for the quarantine pest.
One commenter expressed concern that the addition of taxa to the NAPPRA lists could have a potentially marked effect on importers and those who rely on imported products to sell, as many of the proposed taxa are commonly traded. As an example, the commenter
As described earlier and in the initial notice, in a few cases, taxa we identified as hosts of quarantine pests that should be added to the NAPPRA category would be allowed to be imported from countries that are currently exporting the taxa to the United States, subject to restrictions in a Federal order that was issued previously. The hosts of CLB were previously regulated under a Federal order,
With respect to CLB hosts specifically, we have re-examined our import records in order to ensure that all countries that have had significant trade with the United States and that generally supply pest-free plants for planting in importation are not included in the NAPPRA list. We found several additional countries that needed to be exempted for various host taxa. Specifically:
• All CLB host taxa from Canada are now exempted from the NAPPRA action.
• New Zealand is now exempted from the NAPPRA action for
• Netherlands is now exempted from the NAPPRA action for
• Thailand is now exempted from the NAPPRA action for
• Israel is now exempted from the NAPPRA action for
• France is now exempted from the NAPPRA action for
• Japan is now exempted from the NAPPRA action for
• Korea is now exempted from the NAPPRA action for
• United Kingdom is now exempted from the NAPPRA action for
The CLB data sheet has been amended to reflect these changes; the amended CLB data sheet is available on Regulations.gov at the address listed under footnote 1. The importation of these CLB host taxa from the specified countries will continue to be allowed under the conditions in the Federal order. These changes are consistent with our policy for implementing NAPPRA.
As noted earlier, the exemptions from the NAPPRA action for hosts of CLB are based on our trade records, and we reexamined them in the process of developing this final action. We issued the first Federal order restricting imports of CLB hosts in January 2009; as the statistics cited by the commenter reflect years of trade subject only to the general restrictions in the plants for planting regulations, those statistics may not reflect recent trade patterns. In addition, the statistics include genera that were not included in the NAPPRA action for CLB hosts. We have carefully considered potential impacts on existing trade in developing this action, and we will do so for future NAPPRA actions as well.
The commenter also stated that the nursery industry is under a severe contraction due to the national economy, with many companies failing, and that adding taxa to NAPPRA will likely lead to many additional failures and job loss. In addition, the commenter stated, the action would affect many sales orders and contracts that are in the process of being filled. These are often multi-year agreements, often with plant material originating in multiple countries with specific horticultural traits. Without its intended market, the commenter stated, this material will likely be destroyed, creating a loss for oversees trading partners and potential litigation on U.S. importers.
The Plant Protection Act (7 U.S.C. 7701
In addition, the taxa we proposed to add to the NAPPRA category have not been imported into the United States in significant amounts. As described earlier, for those taxa that have been imported in significant amounts, we are using Federal orders to restrict their importation, rather than adding them to the NAPPRA category. These factors indicate that our listings under NAPPRA are not likely to cause significant economic hardship to U.S. growers.
As noted above, the NAPPRA category includes plants that are quarantine pests and plants that are hosts of quarantine pests. The regulations in § 319.37–1 define
Two commenters generally addressed the concept of plant presence in the United States, asking us to adopt a clear standard for determining whether a plant is not yet present in the United States, or present but not widely distributed and being officially controlled. One stated that a taxon should be considered to be present in the United States when the taxon can be shown to have had multiple entries through importation or when the taxon is available in commercial trade. This commenter also stated that there should be a clearly defined standard against which to judge presence if the record shows one or multiple introductions of the taxon, or natural occurrences for plants whose native habitats exist near the United States' northern or southern borders.
Another commenter agreed that any taxon available in commercial trade should be considered to be present, and also indicated that plant taxa that are in cultivation among specialists should be considered to be present. This commenter also stated that only a small percentage of the people who use the Internet ever post any information on it, meaning that an online report from a grower of a taxon probably represents 10 to 100 other growers who also grow the plant. For that reason, any Internet report of growth of a plant in the United States would indicate that the plant was present in the United States.
We consider a plant taxon to be present in the United States if there is evidence that it is being grown here. Commercial trade, cultivation among specialists, and multiple entries through importation would be evidence that a plant is being grown in the United States. We agree with the second commenter that Internet reports of growth of a plant in the United States would indicate that the plant taxon described was present in the United States. However, we have determined that such information may not necessarily indicate that the taxon is
One commenter stated that taxa that have had some entries into the United States or natural occurrences within the United States with no evidence of invasiveness should not be considered a problem. Another commenter stated that plants that have been imported into the United States sporadically in the past, but that are not currently in cultivation, are not present in the United States. However, the commenter recommended that we consider the fact that the plants did not establish permanently in the United States as evidence against their invasiveness.
Noting that certain taxa that we proposed to add to the NAPPRA category appeared to be present in the United States, one commenter recommended that we put those species under consideration for official control, thus ensuring that they qualify as quarantine pests under the definition. This commenter stated that all species added to the NAPPRA category should be analyzed to determine whether they qualify as Federal noxious weeds under our regulations in 7 CFR part 360.
We generally agree with the first two commenters that taxa that have previously been imported into the United States without problems would not be likely to be considered quarantine pests. However, sometimes the potential economic importance of a taxon's effects on U.S. agricultural and natural resources becomes apparent after importation. New information may also become available indicating that the taxon may pose more of a threat to U.S. agricultural and environmental resources than previously thought. As suggested by the last commenter, these circumstances would spur us to consider placing the taxon under official control by adding it to the list of noxious weeds in 7 CFR part 360.
We determine whether to place a taxon under official control by conducting a weed risk assessment (WRA). If the WRA indicates that official control is necessary, we add the taxon to the list of noxious weeds. Taxa that are present in the United States but not widely distributed and under consideration for official control are potential additions to the NAPPRA category, if they meet the other criteria for being considered a quarantine pest.
We do not automatically conduct WRAs for taxa on the NAPPRA list of quarantine pest plants; people who want a taxon to be removed from the NAPPRA category need to request that a risk analysis be conducted for its removal, as provided in § 319.37–2a(e). However, if we add a taxon to the NAPPRA list of quarantine pest plants in part because we are considering it for official control, then the process of conducting a WRA has already begun, and our decision to remove the taxon from the NAPPRA list or add it to the list of noxious weeds would be based on the results of the WRA.
The first two commenters also mentioned invasiveness as a criterion for adding a plant taxon to NAPPRA. We would like to note that invasiveness in and of itself does not mean that a plant taxon could be considered a quarantine pest; rather, the damage caused by a plant's invasiveness would have to be of potential economic importance.
One commenter stated generally that we should work with private growers and gardeners to monitor plants that are present in the United States and to react quickly if one starts to become a problem.
We agree. We have begun reaching out to gardeners, plant enthusiast societies, and others to share information about plants. We expect that these efforts will help to inform future control efforts.
We made available data sheets detailing the scientific evidence we considered in making the determination that 41 taxa of plants for planting are quarantine pests. We received comments on 21 of those taxa. The comments are discussed below by taxon.
The data sheet we prepared for
However, as described in the data sheet,
As stated in the data sheet,
The FAO Web page cited by the commenter indicates that
For these reasons, we have determined that the introduction of
The history of
Although the taxon may be in trade, there is little information regarding the extent of that trade; its distribution as a naturalized plant is limited to California. For that reason, we have determined that
The data sheet we prepared for this taxon indicated that it is present in Florida and South Carolina (meaning it is not widely distributed) and that it is under consideration for official control. Indeed, we are evaluating
The data sheet we prepared for
We are adding
In order to remove a taxon from the NAPPRA category, we will conduct a PRA for the taxon in accordance with paragraph (e) of § 319.37–2a. We received a few questions on the PRA process, all of which focused on the importation of taxa of plants for planting that we determine to be hosts of quarantine pests.
One commenter asked whether the PRAs will address only the pest for which the taxon was added to the NAPPRA category, or all quarantine pests associated with the taxon and the countries included in the PRA.
The PRAs will be comprehensive and analyze all quarantine pests associated with the taxon in the countries included in the PRA, so that we can address all the risks associated with the importation of the plant taxon.
One commenter asked whether we will consider proposals from foreign national plant protection organizations (NPPOs), accompanied by scientific and technical justifications, for the development of specific import requirements for NAPPRA-listed plants (e.g., systems approach, treatment, post-entry quarantine, etc.) prior to the initiation and completion of a PRA.
We would not authorize the importation of a NAPPRA-listed taxon prior to the completion of a PRA, except under Departmental permit (or CIP, if the proposed rule is finalized). However, any information an exporting country wishes to submit regarding potential mitigations for the pests associated with a taxon would be taken into account during the development of a PRA or the issuance of a Departmental permit or CIP.
One commenter asked about how we will prioritize PRAs, the type of information that will be required for the PRA process, timelines for completion of PRAs, and what actions, if any, can be taken by industry to facilitate the process.
PRAs will be prioritized based on whether we have received a request to conduct them. Requests to remove a taxon from the NAPPRA list must be made in accordance with § 319.5. This section, headed “Requirements for submitting requests to change the regulations in 7 CFR part 319,” allows anyone to submit a request to change the regulations in 7 CFR part 319, but requires the submission of information from an NPPO before a PRA will be prepared.
We strive to complete all PRAs in a timely manner. However, the length of time it takes to complete a PRA is dependent on several factors, some of which are not in APHIS' control:
• The availability of data on the taxon;
• The timeliness with which the foreign NPPO responds to our requests for information; and
• Competition for APHIS' limited resources available for developing PRAs.
These factors mean that we cannot provide a timetable for preparation of a PRA in response to a request to remove a taxon from the NAPPRA category. However, if a foreign country wishes to be able to conduct trade in a taxon with the United States, we would expect that its NPPO would provide information to
In most cases, under the “Action under NAPPRA” heading in the data sheets, we proposed to add taxa that are hosts of quarantine pests to NAPPRA from all countries, rather than just the countries in which the quarantine pest of concern is known to be present.
We received several comments on this policy. One commenter asked whether the pest status of individual countries of origin would be taken into consideration, as designated by the NPPOs of those countries, in order to remove them from the NAPPRA list. Another commenter asked for clarification to be provided on the measures to be implemented in the case of countries where the listed pests are not known to be present.
Our policy in implementing the NAPPRA category is to prevent the importation of hosts from any country, regardless of current pest status, with the following exceptions:
• Taxa of hosts of quarantine pests whose importation we proposed to allow to continue under a Federal order, as described earlier in this document;
• Taxa of hosts of quarantine pests currently being imported from a country in which the pest is not present; and
• Certain taxa from Canada, when Canada is free of the quarantine pest for which the taxa are hosts and when Canada's import regulations and our restrictions specific to Canada ensure that the pest would not be introduced into the United States through the importation of the taxa from Canada.
In general, it is appropriate to add hosts of quarantine pests from all countries to the NAPPRA category because pests can spread quickly from country to country through the movement of plants for planting, and the importation of plants for planting is a high-risk pathway for the introduction of quarantine pests.
Another commenter asked how our policy of adding imports of taxa of hosts of quarantine pests from all countries to the NAPPRA list takes relevant IPPC guidelines into account.
As described above, when a taxon that is a host of a quarantine pest is currently being imported, we take measures other than addition to the NAPPRA category to address the risk associated with that taxon, when such measures are available. For taxa that have not previously been imported, we are following IPPC guidelines by requiring a PRA prior to the importation of a plant taxon from a new country or region.
Under the “Action under NAPPRA” heading, the data sheets for most of the hosts of quarantine pests indicated that the importation of cut flowers of those taxa would be NAPPRA. One commenter stated that cut flowers should be included in the NAPPRA category only where scientifically justified, as cut flowers are generally intended for consumption rather than for introduction into the environment and thus have historically, and correctly, been regarded as posing a level of risk different than that posed by plants for planting.
The commenter expressed specific concerns about including in the NAPPRA category cut flowers from CLB host taxa, one of which is the genus
Another commenter agreed that stems 10 mm or smaller in diameter are not likely to transport viable individuals of CLB, but expressed concern regarding larger stems of roses intended for planting, even from the European Union; the commenter stated that the European Union lacks effective border controls and that CLB is established in Italy.
One commenter stated that CLB larvae are not found in host plant material smaller than 10 mm in diameter, meaning such material should be exempt from NAPPRA.
We agree that cut flowers are intended for consumption rather than for propagation. However, cut flowers can be used for propagation, and if so used can transmit quarantine pathogens. The definitions of
Nevertheless, the commenter is correct that it is important to evaluate whether cut flowers of a taxon of plants for planting are capable of introducing the pest in question before including them in the NAPPRA action for that taxon. We reexamined the taxa we had proposed to add to NAPPRA as hosts of quarantine pests and found that the insect quarantine pests (CLB;
We are updating the “Action under NAPPRA” sections of the data sheets for CLB and the palm weevils to reflect the fact that cut flowers of taxa that are hosts of these pests will not be regulated under NAPPRA. However, the importation of cut flowers from hosts of all three of these quarantine pests is restricted in Federal orders, and those restrictions will remain in place. With respect to CLB, the Federal order for CLB exempts stems 10 mm and less in diameter from regulation, as noted earlier, and imposes production and certification requirements on larger stems and on other plants for planting from countries where CLB is known to occur (including the European Union).
The other quarantine pests addressed in the data sheets are all pathogens, and cut flowers from any of the host taxa can serve as a pathway for the introduction of the quarantine pest and can be used for planting. For that reason, we are adding cut flowers of those taxa (as well as all other plant parts other than seed) to the NAPPRA category.
We are not, however, exempting any plant material less than 10 mm in diameter from a CLB host taxon from the NAPPRA category. Such plants are likely intended for propagation, and in order to authorize their importation from a new source we would need to conduct a PRA to analyze all the relevant risks associated with their importation.
Two commenters stated that seed should be allowed to be imported if the taxon is a host of a quarantine pest (rather than a quarantine pest itself), the
One commenter expressed concern that our proposed addition of taxa such as
Two commenters expressed specific concern about the designation of
We have recognized that seed poses different risks than other plant parts. In the May 2011 final rule, we stated that we would continue to allow the importation of seed from taxa that were added to the NAPPRA list of hosts of quarantine pests, unless there was evidence that the quarantine pest could be introduced via seed. The “Action under NAPPRA” sections for all of the taxa that we determined to be hosts of quarantine pests (including
One commenter stated that we should take into account the size of the importation, as small lots of seed are of a decidedly lower order of risk than bulk commercial shipments of plants or seed.
We agree that the risk of introducing a quarantine pest through imported plants for planting increases with the size of the shipment. However, for plants for planting that are themselves quarantine pests, a single seed could be enough to introduce the quarantine pest and allow it to establish. That is why, for quarantine pest plants, the importation of seed of those taxa is NAPPRA. In addition, in the regulations allowing the importation of small lots of seed without a phytosanitary certificate in § 319.37–4(d), we do not allow the importation of small lots of seed from taxa whose seed is listed as NAPPRA.
One commenter stated that tissue-cultured plants from taxa listed as NAPPRA should be allowed to be imported, as scientific evidence indicates that pests would not accompany tissue-cultured material.
Two commenters stated that the importation of in vitro tissue cultures of
While properly tissue-cultured plants are pest-free, plants that are infested with disease prior to tissue culture are likely to be infested when the plant comes out of tissue culture as well. Plants that are added to the NAPPRA list as hosts of an insect quarantine pest may be free of that pest, but there may be other plant pests for which tissue culturing is not an adequate mitigation, or for which there may be special requirements for tissue culturing. In order to fully consider whether tissue culture is an adequate mitigation for all the pests associated with a taxon of plants for planting, we would need to conduct a PRA. Therefore, we cannot allow the importation of tissue cultures of plant taxa listed as NAPPRA. Similarly, roots may be hosts for additional pests for which we would need to conduct a PRA, and we cannot allow the importation of roots from plant taxa listed as NAPPRA.
For
Under the “Action under NAPPRA” heading of the data sheets for taxa that we determined to be hosts of quarantine pests, we stated for some taxa that we would continue to allow the importation of the taxon from Canada. We stated in the initial notice that we would allow such importation when Canada is free of the quarantine pest for which the taxa are hosts and when Canada's import regulations and our restrictions specific to Canada ensure that the pest would not be introduced into the United States through the importation of the taxa from Canada.
One commenter, the NPPO of Canada, asked us to allow the continued importation from Canada of several taxa that are hosts of quarantine pests in addition to those specified in the initial data sheets. Specifically, the NPPO of Canada asked that we allow the continued importation of hosts of CLB, the red palm weevil, the giant palm weevil, and the pests
We agree with this commenter with respect to hosts of CLB. Most host taxa of CLB are commonly cultivated in Canada, and Canada has put in place restrictions on the importation of all CLB host taxa from other countries. As noted earlier in this document, the data sheet for CLB has been updated to indicate that the importation of hosts of this pest from Canada is not restricted under NAPPRA.
With respect to the hosts of the rest of the pests the commenter named, Canada has not yet implemented regulations that are equivalent to adding the host taxa to the NAPPRA category. In addition, it is unlikely that hosts of these pests would be cultivated in Canada, as the pests affect tropical plants, specifically kiwi, mango, palm, and pomegranate plants. Therefore, plants of these taxa that are present in Canada would likely have been imported; if they were imported from an area other than the United States, they could pose a risk of introducing a quarantine pest into the United States, should they be re-exported to the United States. Accordingly, we will continue to include Canada in the list of countries from which the importation of hosts of the red palm weevil, the giant palm weevil,
If Canada successfully imposes equivalent import restrictions on hosts of these pests in the future, we will reevaluate our decisions.
One commenter, representing the European Union, noted that 72 taxa of plants for planting were designated as hosts of CLB and thus potential additions to the NAPPRA category, but the pests and pest risks associated with these taxa are well known, since the pest of concern has already been identified. The commenter asked us to clarify the need for strengthening the import requirements for these taxa from the European Union.
We have identified the taxa listed in the CLB data sheet as hosts of a quarantine pest. This indicates that
The commenter asked us to share our technical documentation on the host range of CLB as well as any data on interceptions of CLB in plants from the European Union.
The technical documentation on the host range of CLB is presented in the CLB data sheet. We do not have interception data for CLB from the European Union, for two reasons. First, except for the specific countries from which imports of certain CLB host taxa will continue to be allowed, as described in the amended data sheet available with this final notice, the countries in the European Union have not exported significant quantities of CLB host taxa to the United States. Second, CLB is an internal borer, and such pests are not readily apparent through the visual inspection we conduct at plant inspection stations, which makes it all the more important to develop other means to combat this and any other quarantine pests associated with the CLB host taxa, through the PRA process. As discussed earlier, the importation of CLB host taxa has been subject to mitigations against the introduction of CLB that are set out in a Federal order, and any importation of CLB host taxa that continues after the publication of this notice will occur under the same mitigations.
The data sheet for CLB listed CLB as present in the European Union, among other areas. The commenter stated that most European Union Member States can claim that CLB is not known to occur, based on several years of mandatory annual surveillance. The commenter stated that areas where CLB is established have been demarcated officially, and measures are imposed to ensure that no infested material can leave these areas. The commenter further stated that there are no indications that CLB is present outside demarcated areas, with the exception of isolated findings that can be traced back to imports. The commenter concluded that the entire European Union should not be listed as an area where CLB is present.
As stated in this document, unless we have had significant trade in CLB host taxa with a country, imports of CLB host taxa from all countries will be NAPPRA. As previously established, the countries that comprise the European Union have not exported significant quantities of CLB host taxa to the United States, with limited exceptions as described in the data sheets. Therefore, it does not matter whether CLB is present in the entire European Union or in certain areas for the purposes of this action.
With respect to the assertions made by the commenter, we note that, in the European Union, CLB has been found in the environment surrounding nursery areas, suggesting that infested host material was moved into previously uninfested areas, and may also have moved out of those areas. This would indicate some potential deficiencies in the European Union's regulatory program for this pest. We would undertake a detailed review of the European Union's program for CLB if the European Union requests that we conduct a PRA to allow the importation of CLB host taxa into the United States.
One commenter requested clarification regarding the rationale for adding
We believe the measures the commenter cited are those in paragraphs (b) and (j) of § 319.37–5. These measures specifically address pathogens that may be associated with these genera of fruit trees. They do not provide any protection against CLB. In addition, they do not address other insect or pathogen pests that may be associated with these genera. In order to comprehensively address the risk associated with the importation of these taxa, we need to complete a PRA.
Several commenters expressed concern regarding the potential impact on the bonsai trade of listing
The commenters stated that the importation of
Based on these comments, we re-examined our import records to determine whether there was significant trade in
Noting that the importation of bonsai is regulated under § 319.37–5(q), one commenter suggested we should continue to allow the importation of any taxon that is to be listed in NAPPRA as a host of a quarantine pest if the taxon is produced in accordance with a USDA-approved systems approach.
The conditions in § 319.37–5(q) were developed to address the risk posed by
As discussed earlier, in cases where we have experience with importing artificially dwarfed plants under § 319.37–5(q) and the CLB Federal order and have found, through inspection, that they are generally pest-free, we have allowed that trade to continue under the conditions of the Federal order.
One commenter, a company primarily focused on the establishment and management of short rotation plantations of hybrid poplar in North America, Europe, Asia, and South America, expressed concern about the listing of
The importation of seed of
One commenter stated a desire to establish a pest-free area for CLB and the Asian longhorned beetle (
As described in the CLB data sheet that accompanied the July 2011 notice,
One commenter expressed surprise that we had excluded Canada from NAPPRA in the data sheet listing hosts of the pest
Both Canada and the United States have designated areas under quarantine for this pest. We recognize Canada's quarantine, and Canada recognizes ours. There is no need for further restrictions.
Therefore, in accordance with the regulations in § 319.37–2a(b)(2), we are adding 31 taxa of plants for planting that are quarantine pests and 107 taxa of plants for planting that are hosts of 13 quarantine pests to the list of taxa whose importation is NAPPRA. A complete list of those taxa and the restrictions placed on their importation can be found at the address in footnote 1 of this document or on the Plant Protection and Quarantine Web page at
7 U.S.C. 450, 7701–7772, and 7781–7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Forest Service, USDA.
Notice of meeting.
The National Advisory Committee for Implementation of the National Forest System Land Management Planning Rule will meet in Fort Collins, Colorado. The committee operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to provide advice and recommendations on the implementation of the National Forest System Land Management Rule. The meeting is also open to the public. The purpose of the meeting is to initiate deliberations on formulating advice to the Secretary on the Proposed Land Management Planning Directives.
The meeting will be held on May 7–9, 2013, from 8:30 a.m. to 6:00 p.m. on Tuesday, 8:30 a.m. to 5:30 p.m. on Wednesday, and 8:30 a.m. to 1:30 p.m. on Thursday, Mountain Time.
The meeting will be held at the Hilton Fort Collins, 425 West Prospect Road, Fort Collins, Colorado 80526.
Written comments may be submitted as described under Supplementary Information. All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at 1601 N Kent Street, Arlington, VA 22209, 6th Floor. Please contact ahead of time, Chalonda Jasper at 202–260–9400,
Chalonda Jasper, Ecosystem Management Coordination, 202–260–9400, cjasper@fs.fed.us.
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1–800–877–8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.
The following business will be conducted: (1) Initial deliberations on formulating advice for the Secretary on the Proposed Land Management Planning Directives, (2) discuss findings from committee working groups, and (3) administrative tasks. Further information, including
Anyone who would like to bring related matters to the attention of the committee may file written statements with the committee staff before the meeting. Written comments must be sent to USDA Forest Service, Ecosystem Management Coordination, 201 14th Street SW., Mail Stop 1104, Washington, DC, 20250–1104. Comments may also be sent via email to Chalonda Jasper at
On December 14, 2012, Abbott Laboratories, Inc., and AbbVie, Inc., submitted a notification for expanded production authority within Subzones 22F and 22S, respectively, at sites located in the North Chicago and Lake County, Illinois, area.
The notification was processed in accordance with the regulations of the FTZ Board (15 CFR part 400), including notice in the
On November 19, 2012, Georgia Foreign-Trade Zone, Inc., grantee of FTZ 26, submitted a notification of proposed production activity to the Foreign-Trade Zones (FTZ) Board on behalf of Suzuki Mfg. of America Corp.
The notification was processed in accordance with the regulations of the FTZ Board (15 CFR part 400), including notice in the
The Piedmont Triad Partnership, grantee of FTZ 230, submitted a notification of proposed production activity on behalf of Oracle Flexible Packaging, Inc. (OFPI), located in Winston-Salem, North Carolina. The notification conforming to the requirements of the regulations of the FTZ Board (15 CFR 400.22) was received on March 25, 2013.
The OFPI facility is located within Site 28 of FTZ 230. The facility is used for the production of aluminum foil-backed paperboard and to laminate plastic film (the laminating activity is not “production” activity under the FTZ Board's regulations). Pursuant to 15 CFR 400.14(b), FTZ activity would be limited to the specific foreign-status materials and components and specific finished products described in the submitted notification (as described below) and subsequently authorized by the FTZ Board.
Production under FTZ procedures could exempt OFPI from customs duty payments on the foreign status materials and components used in export production. On its domestic sales, OFPI would be able to choose the duty rates during customs entry procedures that apply to aluminum foil-backed paperboard and aluminum scrap (free—3.7%) for the foreign aluminum foil noted below. Customs duties also could possibly be deferred or reduced on foreign status production equipment.
The components and materials sourced from abroad include: aluminum foil (not backed) and plastic (propylene) film (duty rate ranges from 3.0 to 5.8%).
Public comment is invited from interested parties. Submissions shall be addressed to the FTZ Board's Executive Secretary at the address below. The closing period for their receipt is May 28, 2013.
A copy of the notification will be available for public inspection at the Office of the Executive Secretary, Foreign-Trade Zones Board, Room 21013, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230–0002, and in the “Reading Room” section of the FTZ Board's Web site, which is accessible via
For further information, contact Pierre Duy at
Import Administration, International Trade Administration, Department of Commerce.
On December 11, 2012, the Department of Commerce (the
Effective Date: April 18, 2013.
David Goldberger or Terre Keaton Stefanova, AD/CVD Operations, Office 2, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC, 20230; telephone (202) 482–4136 or (202) 482–1280, respectively.
Since the publication of the
The Department has conducted this administrative review in accordance with section
751(a)(1) of the Tariff Act of 1930, as amended (the Act).
The merchandise covered by the order is lightweight thermal paper. The merchandise subject to the order is currently classified under the following Harmonized Tariff Schedule of the United States (HTSUS) subheadings: 3703.10.60, 4811.59.20, 4811.90.8000, 4811.90.8030, 4811.90.8040, 4811.90.8050, 4811.90.9000, 4811.90.9030, 4811.90.9035, 4811.90.9050, 4811.90.9080, 4811.90.9090, 4820.10.20, and 4823.40.00. Although the HTSUS numbers are provided for convenience and customs purposes, the written product description, available in the
In the
All issues raised in the case and rebuttal briefs by parties are addressed in the memorandum entitled, “Issues and Decision Memorandum for the Final Results of the 2010–2011 Administrative Review on Lightweight Thermal Paper from Germany (Issues and Decision Memo),” which is dated concurrently with, and adopted by, this notice. A list of the issues which parties raised and to which we respond in the Issues and Decision Memo is attached to this notice as Appendix I. The Issues and Decision Memo is a public document and is on file electronically via Import Administration's Antidumping and Countervailing Duty Centralized Electronic Service System (IA ACCESS). IA ACCESS is available to registered users at
We made no changes to our preliminary results. Therefore, we are assigning the following dumping margin to Koehler for the period November 1, 2010, through October 31, 2011.
The Department will determine, and U.S. Customs and Border Protection (CBP) shall assess, antidumping duties on all appropriate entries, in accordance with 19 CFR 351.212(b). The Department intends to issue appropriate assessment instructions directly to CBP 15 days after publication of these final results of review. For Koehler's U.S. sales, we will base the assessment rate assigned to the corresponding entries on AFA, as noted above.
The following cash deposit requirements will be effective for all shipments of lightweight thermal paper from Germany entered, or withdrawn from warehouse, for consumption on or after the publication date of the final results of this administrative review, as provided by section 751(a)(2)(C) of the Act: (1) The cash deposit rate for Koehler will be the rate established in the final results of this administrative review; (2) for previously reviewed or investigated companies not participating in this review, the cash deposit rate will continue to be the company-specific rate published for the most recent period; (3) if the exporter is not a firm covered in this review, a previous review, or the original less-than-fair-value investigation, but the manufacturer is, the cash deposit rate will be the rate established for the most recent period for the manufacturer of the merchandise; and (4) the cash deposit rate for all other manufacturers or exporters will continue to be 6.50 percent, the all-others rate established in the investigation.
This notice also serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement
This notice serves as the only reminder to parties subject to administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
This administrative review and notice are published in accordance with sections 751(a)(1) and 777(i)(1) of the Act and 19 CFR 351.221.
1. Application of Total Adverse Facts Available (AFA).
2. Selection of the AFA Rate.
Import Administration, International Trade Administration, Department of Commerce.
The Department of Commerce (“the Department”) is rescinding the administrative review of the countervailing duty order on lightweight thermal paper from the People's Republic of China (“PRC”) for the period January 1, 2011, through December 31, 2011.
Mahnaz Khan, AD/CVD Operations, Office 1, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482–0914.
The Department initiated an administrative review of the countervailing duty order on lightweight thermal paper from the PRC covering the period January 1, 2011, through December 31, 2011, based on a request by Appleton Papers, Inc. (“Petitioner”).
The review covers the following companies: Guangdong Guanhao High-Tech Co., Ltd.; Henan Province Jianghe Paper Co., Ltd.; Jianghe Paper Co., Ltd.; JHT Paper; New Pride Co., Ltd.; and Shenzhen Taizhou Industrial Development Co., Ltd. On April 1, 2013, Petitioner withdrew its request for an administrative review of these companies.
Pursuant to 19 CFR 351.213(d)(1), the Department will rescind an administrative review, in whole or in part, if the party that requested the review withdraws its request within 90 days of the date of publication of the notice of initiation of the requested review. In this case, Petitioner withdrew its request within the 90-day deadline and no other parties requested an administrative review of the countervailing duty order. Therefore, we are rescinding the administrative review of lightweight thermal paper from the PRC covering the period January 1, 2011, through December 31, 2011.
The Department will instruct U.S. Customs and Border Protection (“CBP”) to assess countervailing duties on all entries of lightweight thermal paper from the PRC during the POR at rates equal to the cash deposit of estimated countervailing duties required at the time of entry or withdrawal from warehouse for consumption, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions to CBP 15 days after publication of this notice.
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of countervailing duties prior to liquidation of the relevant entries during this review period.
This notice serves as a final reminder to parties subject to administrative protective order (“APO”) of their responsibility concerning the return or destruction of proprietary information disclosed under an APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation that is subject to sanction.
This notice is issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Tariff Act of 1930, as amended, and 19 CFR 351.213(d)(4).
NOAA's National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), U.S. Department of Commerce.
Issuance of a scientific research permit.
Notice is hereby given that NMFS has issued scientific research Permit 15610 to the Oregon State University, Department of Fisheries and Wildlife (OSU).
The permit application, the permit, and related documents are available for review, by appointment, at the foregoing address at: Protected Resources Division, NMFS, 501 W. Ocean Blvd., Suite 4200, Long Beach, CA 90802 phone: 562–980–4026, fax: 562–980–4027, email at:
Matt McGoogan at 562–980–4026, or email:
The issuance of permits, as required by the Endangered Species Act of 1973 (16 U.S.C. 1531–1543) (ESA), is based on a finding that such permits: (1) Are applied for in good faith; (2) would not operate to the disadvantage of the listed species that are the subject of the permits; and, (3) are consistent with the purposes and policies set forth in section 2 of the ESA. Authority to take listed species is subject to conditions set forth in the permits. Permits are issued in accordance with and are subject to the ESA and NMFS regulations (50 CFR parts 222–226) governing listed fish and wildlife permits.
This notice is relevant to the federally endangered Southern California Distinct Population Segment of steelhead (
A notice of the receipt of an application for Permit 15610 was published in the
Research activities include (1) monitoring water temperature, (2) capturing smolts and adult steelhead in a migrant trap at the Robles Diversion Dam, (3) capturing smolts and juvenile steelhead using a seine in the Ventura River estuary, (4) capturing smolts and juvenile steelhead by electrofishing pre-determined sample sites throughout the Ventura River watershed, (5) recording weight and length of smolts and juvenile steelhead, (6) removing tissue (gill and fin clip) samples from smolts and juvenile steelhead, (7) analyzing fin clips for genetic structure, (8) analyzing gill samples for ATPase (decomposition of adenosine triphosphate (ATP) into adenosine diphosphate and a free phosphate ion as an indicator of smoltification, and (9) inserting Passive Integrated Transponder (PIT) tags into smolts and juvenile steelhead.
Permit 15610 authorizes the non-lethal capture and release of up to 210 juvenile steelhead (30 juvenile steelhead from 7 different sites) over the course of 1 year for the purpose of genetic sampling (fin clip), the capture and release of up to 684 steelhead smolts (342 smolts annually over 2 years of sampling) and 304 juvenile steelhead (152 juvenile steelhead annually over 2 years of sampling) for the purpose of PIT tagging and tissue (gill/ATPase) sampling, capture and release of up to 10 adult steelhead (5 adults annually over 2 years of sampling) for genetic sampling (fin clip), and up to 40 tissue samples (fin clip) from adult steelhead carcasses (20 adult carcasses annually over 2 years of sampling). The authorized unintentional lethal take for Permit 15610 is a total of 9 juvenile steelhead and 16 steelhead smolts. All mortalities will be sent to NMFS Protected Resources Division in Long Beach, California for genetic research and processing. Field activities associated with Permit 15610 began after the permit was issued on March 4, 2013, and will cease when the permit expires on May 31, 2015.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a public meeting.
The Scientific and Statistical Committee (SSC) of the Mid-Atlantic Fishery Management Council (Council) will hold a meeting.
The meeting will be held on Wednesday and Thursday, May 15–16, 2013. The meeting will begin at 9 a.m. on Wednesday, May 15 and conclude by 4 p.m. on Thursday, May 16.
The meeting will be held at Admiral Fell Inn, 888 S. Broadway, Baltimore, MD 21231; telephone: (410) 522–7377.
Council address: Mid-Atlantic Fishery Management Council, 800 N. State Street, Suite 201, Dover, DE 19901; telephone: (302) 674–2331.
Christopher M. Moore Ph.D., Executive Director, Mid-Atlantic Fishery Management Council, 800 N. State Street, Suite 201, Dover, DE 19901; telephone: (302) 526–5255.
Agenda items for the SSC meeting include: review multi-year ABC specifications for
Although non-emergency issues not contained in this agenda may come before this group for discussion, those issues may not be the subject of formal action during this meeting. Action will be restricted to those issues specifically listed in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Fishery Conservation and Management Act, provided the public has been notified of the Council's intent to take final action to address the emergency.
The meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to M. Jan Saunders at the Mid-Atlantic Council Office, (302) 526–5251, at least 5 days prior to the meeting date.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of open public meeting.
This notice sets forth the schedule and proposed agenda of a
The meeting will be held May 9, 2013 from 1 p.m. to 5 p.m. and May 10, 2013, from 8 a.m. to 5 p.m.
On May 9, the meeting will be held at the Mayflower Renaissance, 1127 Connecticut Avenue NW., Washington, DC 20036; 202–776–9145. On May 10, the meeting will be at the Courtyard Washington Embassy Row, 1600 Rhode Island Avenue NW., Washington, DC 20036; 202–293–8000.
Mark Holliday, MAFAC Executive Director; (301) 427–8004; email:
As required by section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. 2, notice is hereby given of a meeting of MAFAC. The MAFAC was established by the Secretary of Commerce (Secretary), and, since 1971, advises the Secretary on all living marine resource matters that are the responsibility of the Department of Commerce. The complete charter and summaries of prior meetings are located online at
This agenda is subject to change.
The meeting is convened to hear presentations and discuss policies and guidance on the following topics: Fisheries certification and sustainability, Endangered Species Act and current protected resources issues, outcomes of the Managing Our Nation's Fisheries 3 conference and next steps, and NMFS budget. The meeting will include discussion of various MAFAC administrative and organizational matters and may include meetings of the standing subcommittees.
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Mark Holliday, MAFAC Executive Director; 301–427–8004 by April 26, 2013.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Meetings of the South Atlantic Fishery Management Council's Habitat & Environmental Protection Advisory Panel (AP); Coral AP; Joint Meeting of the Habitat & Environmental Protection AP and Coral AP; and Deepwater Shrimp AP.
The South Atlantic Fishery Management Council (SAFMC) will hold the AP meetings in North Charleston, SC.
The meetings will be held from 8:30 a.m. on Tuesday, May 7, 2013 until 5 p.m. on Thursday, May 9, 2013.
The meetings will be held at the Hilton Garden Inn, 5265 International Boulevard, North Charleston, SC 29418; telephone: (800) 445–8667 or (843) 308–9330; fax: (843) 308–9331.
Kim Iverson, Public Information Officer, SAFMC; telephone: (843) 571–4366 or toll free: (866) SAFMC–10; fax: (843) 769–4520; email:
The items of discussion in the individual meeting agendas are as follows:
1. Review draft Essential Fish Habitat (EFH) policy statements.
2. Review status of developing a state of the South Atlantic Habitat report.
3. Receive an update on regional ecosystem coordination and South Atlantic Habitat and Ecosystem Atlas/Digital Dashboard.
4. Receive a project/permit update from NOAA Fisheries Habitat Conservation Division.
1. Receive an update from NOAA Fisheries Habitat Conservation Division.
2. Receive an update on Coral Nursery Restoration Work and Utilization.
3. Receive an update on the status of the Endangered Species Act (ESA) listing of coral species.
4. Review Coral AP recommendations in Coral Amendment 8, pertaining to Coral Habitat Areas of Particular Concern (HAPCs) and transit through the Oculina HAPC.
5. Proceed with the election of a vice-chair for the AP.
1. Receive an update on Vessel Monitoring Systems (VMS) data.
2. Review Coral Amendment 8 and recommendations for protecting deepwater habitat complexes associated with extension proposals for Coral HAPCs.
1. Receive and discuss Coral Amendment 8, including a review of spatial information on habitat mapping and fishery activity for the modified Coral HAPC area alternatives.
2. Receive a presentation on VMS functionality from NMFS Office of Law Enforcement.
Although non-emergency issues not contained in this agenda may come before this group for discussion, those issues may not be the subject of formal action during these meetings. Action will be restricted to those issues specifically identified in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Fishery Conservation and Management Act, provided the public has been notified of the Council's intent to take final action to address the emergency.
These meetings are physically accessible to people with disabilities. Requests for auxiliary aids should be directed to the council office (see
The times and sequence specified in this agenda are subject to change.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; receipt of applications for permit modification.
Notice is hereby given that the North Carolina Cooperative Fish and Wildlife Research Unit, North Carolina State University, Raleigh, NC 27695 [Joseph Hightower: Responsible Party], has applied in due form for permit modifications to take shortnose sturgeon (
Written, telefaxed, or email comments must be received on or before May 20, 2013.
The application and related documents are available for review by selecting “Records Open for Public Comment” from the
These documents are also available upon written request or by appointment in the following offices:
• Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301) 427–8401; fax (301) 713–0376; and
• Southeast Region, NMFS, 263 13th Avenue South, Saint Petersburg, Florida 33701; phone (727) 824–5312; fax (727) 824–5309.
Written comments on either application should be submitted to the Chief, Permits and Conservation Division
• By email to
• By facsimile to (301) 713–0376; or
• At the address listed above.
Those individuals requesting a public hearing should submit a written request to the Chief, Permits and Conservation Division at the address listed above. The request should set forth the specific reasons why a hearing on the application would be appropriate.
Malcolm Mohead or Colette Cairns at (301) 427–8401.
The subject permit modifications are requested under the authority of the Endangered Species Act of 1973, as amended (ESA; 16 U.S.C. 1531
Permit No. 14759 was issued August 20, 2010 (75 FR 53278), and Permit No. 16375 was issued on April 6, 2012 (77 FR 21754) to the applicant listed above. Each permit currently authorizes the permit holder to assess the presence, abundance, and distribution of shortnose sturgeon and Atlantic sturgeon, respectively, within North Carolina rivers (Chowan, Roanoke, Tar-Pamlico, Neuse, and Cape Fear) and estuaries (Albemarle Sound) using non-lethal sampling methods, using hydroacoustic surveys (side-scan, DIDSON) and gill nets. The permit holder is now requesting authorization to modify both permits to allow use of artificial substrates for characterizing spawning activity in the Roanoke and/or Cape Fear Rivers. Specifically, it is proposed that artificial substrates be used for collecting up to 50 shortnose sturgeon and 50 Atlantic sturgeon early life stages (ELS) per river annually. Proposed sampling for ELS would be conducted up to the first impassible dam, i.e., river kilometer 221 in the Roanoke River and river kilometer 300 in the Cape Fear River. The artificial substrates for collecting sturgeon ELS would be made from floor buffing pads, approximately 2 feet in diameter, and these would anchored to the river bottom and marked with a buoy. The pads would be monitored at least twice per week during suspected spawning runs of either species. The modifications would be valid until the respective permits expire on August 19, 2015 (File No. 14759), and April 5, 2017 (File No. 16375).
Corporation for National and Community Service.
Notice.
The Corporation for National and Community Service (CNCS) has submitted a modification to a currently approved public information collection request (ICR) entitled Senior Corps Grant Application for review and approval in accordance with the Paperwork Reduction Act of 1995, Public Law 104–13, (44 U.S.C. Chapter 35). Copies of this ICR, with applicable supporting documentation, may be obtained by calling the Corporation for National and Community Service, Wanda Carney, at (202) 606–6934 or email to
Comments may be submitted, identified by the title of the information collection activity, to the Office of Information and Regulatory Affairs, Attn: Ms. Sharon Mar, OMB Desk Officer for the Corporation for National and Community Service, by any of the following two methods within 30 days from the date of publication in the
(1)
(2)
The OMB is particularly interested in comments which:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of CNCS, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Propose ways to enhance the quality, utility, and clarity of the information to be collected; and
• Propose ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submissions of responses.
The 60-day
Department of Defense, Defense Security Cooperation Agency.
Notice.
The Department of Defense is publishing the unclassified text of a section 36(b)(1) arms sales notification. This is published to fulfill the requirements of section 155 of Public Law 104–164 dated July 21, 1996.
Ms. B. English, DSCA/DBO/CFM, (703) 601–3740.
The following is a copy of a letter to the Speaker of the House of Representatives, Transmittals 13–10 with attached transmittal, policy justification, and Sensitivity of Technology.
Transmittal No. 13–10
Notice of Proposed Issuance of Letter of Offer
Pursuant to Section 36(b)(1)
of the Arms Export Control Act, as amended
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
* as defined in Section 47(6) of the Arms Export Control Act.
The Government of the Republic of Korea has requested a possible sale of (60) F–35 Joint Strike Fighter Conventional Take Off and Landing (CTOL) aircraft. Aircraft will be configured with the Pratt & Whitney F–135 engines, and (9) Pratt & Whitney F–135 engines are included as spares. Other aircraft equipment includes: Electronic Warfare Systems; Command, Control, Communication, Computer and Intelligence/Communication, Navigational and Identification (C4I/CNI); Autonomic Logistics Global Support System (ALGS); Autonomic Logistics Information System (ALIS); Full Mission Trainer; Weapons Employment Capability, and other Subsystems, Features, and Capabilities; F–35 unique infrared flares; reprogramming center; F–35 Performance Based Logistics. Also included: software development/integration, aircraft ferry and tanker support, support equipment, tools and test equipment, communication equipment, spares and repair parts, personnel training and training equipment, publications and technical documents, U.S. Government and contractor engineering and logistics personnel services, and other related elements of logistics and program support. The estimated cost is $10.8 billion.
This proposed sale will contribute to the foreign policy goals and national security objectives of the United States by meeting the legitimate security and defense needs of an ally and partner nation. The Republic of Korea continues to be an important force for peace, political stability, and economic progress in North East Asia.
The proposed sale of F–35s will provide the Republic of Korea (ROK) with a credible defense capability to deter aggression in the region and ensure interoperability with U.S. forces. The proposed sale will augment Korea's operational aircraft inventory and enhance its air-to-air and air-to-ground self-defense capability. The ROK's Air Force F–4 aircraft will be decommissioned as F–35's are added to the inventory. Korea will have no difficulty absorbing these aircraft into its armed forces.
The proposed sale of this aircraft system and support will not negatively alter the basic military balance in the region.
The prime contractors will be Lockheed Martin Aeronautics Company in Fort Worth, Texas; and Pratt & Whitney Military Engines in East Hartford, Connecticut. This proposal is being offered in the context of a competition. If the proposal is accepted, it is expected that offset agreements will be required.
Implementation of this proposed sale will require multiple trips to Korea involving U.S. Government and contractor representatives for technical reviews/support, program management, and training over a period of 15 years. U.S. contractor representatives will be required in Korea to conduct Contractor Engineering Technical Services (CETS) and Autonomic Logistics and Global Support (ALGS) for after-aircraft delivery.
There will be no adverse impact on U.S. defense readiness as a result of this proposed sale.
(vii)
1. The F–35 Conventional Take-Off and Landing (CTOL) Block 3 aircraft is classified Secret, except as noted below. It contains current technology representing the F–35 low observable airframe/outer mold line, Pratt & Whitney engine, radar, integrated core processor central computer, mission systems/electronic warfare suite, a multiple sensor suite, operational flight and maintenance trainers, technical data/documentation, and associated software. As the aircraft and its subsystems are under development, many specific identifying equipment/system nomenclatures have not been assigned to date. Sensitive and classified elements of the F–35 CTOL Block 3 aircraft include hardware, accessories, components, and associated software for the following major subsystems:
a. The Propulsion system is classified Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret. The single 40,000-lb thrust class engine is designed for low observability and has been integrated into the aircraft system, Pratt & Whitney, with the F135, is developing and producing engine turbo machinery compatible with the F–35 and assures highly reliable, affordable performance. The engine is designed to be utilized in all F–35 variants, providing unmatched commonality and supportability throughout the worldwide base of F–35 users. The CTOL propulsion configuration consists of a main engine, diverterless supersonic inlet, and a Low Observable Axisymmetric Nozzle (LOAN).
b. The AN/APG–81 Active Electronically Scanned Array (AESA) provides mission systems with air-to-air and air-to-ground tracks which the mission system uses as a component to sensor fusion. The AESA allows the radar to direct RF energy in a way that does not expose the F–35, allowing it to maintain low observability in high-threat environments. The radar subsystem supports integrated system performance for air-to-air missions by providing search, track, identification, and AIM–120 missile data link functionality. The radar also provides synthetic aperture radar mapping for locating surface targets and weather mapping for weather avoidance. The radar functions are tightly integrated, interleaved, and managed by an interface to sensor management functions within mission software. The hardware and software are classified Secret.
c. The Electro Optical Targeting System (EOTS) contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret. The EOTS subsystem to the sensor suite provides long-range detection; infrared targeting and tracking systems to support weapon employment. It incorporates a missile-quality Infrared Search and Track (IRST) capability, a Forward-Looking Infrared (FLIR) sensor for precision tracking, and Bomb Damage Indication (BDI) capability. EOTS replaces multiple separate internal or podded systems typically found on legacy aircraft. The
d. The Electro-Optical Distributed Aperture System (EODAS) is a subsystem to the sensor suite and provides full spherical coverage for air-to-air and air-to-ground detection and Navigation Forward Looking Infrared (NFLIR) imaging. The system contains both Secret and Unclassified elements and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret. The NFLIR capability provides infrared (IR) imagery directly to the pilot's Helmet-Mounted Display for navigation in total darkness, including takeoff and landing, and provides a passive IR input to the F–35's sensor fusion algorithms. The all-aspect missile warning function provides time-critical warnings of incoming missiles and cues other subsystems to provide effective countermeasure employment. EODAS also provides an IRST function that can create and maintain Situational Awareness-quality tracks (SAIRST). EODAS is a mid-wave Infrared (IR) system consisting of six identical sensors distributed around the F–35 aircraft. Each sensor has a corresponding airframe window panel integrated with the aircraft structure to meet aerodynamic and stealth requirements.
e. The Electronic Warfare (EW) system contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret. Sensitive elements include: apertures; radio frequency (RF) and infrared (IR) countermeasures; and Electronic Countermeasures (ECM) techniques and features. The reprogrammable, integrated system provides radar warning and electronic support measures (ESM) along with a fully integrated countermeasures (CM) system. The EW system is the primary subsystem used to enhance situational awareness, targeting support and self defense through the search, intercept, location and identification of in-band emitters and to automatically counter IR and RF threats. The IR and RF countermeasures are classified Secret. This system uses low signature-embedded apertures, located in the aircraft control surface edges, to provide direction finding and identification of surface and airborne emitters and the geo-location of surface emitters. The system is classified Secret.
f. The Command, Control, Communications, Computers and Intelligence/Communications, Navigation, and Identification (C4I/CNI) system provides the pilot with unmatched connectivity to flight members, coalition forces, and the battlefield. It is an integrated subsystem designed to provide a broad spectrum of secure, anti-jam, covert voice and data communications, precision radio navigation and landing capability, self-identification, beyond visual range target identification, and connectivity with off-board sources of information. The functionality is tightly integrated within the mission system for enhanced efficiency and effectiveness in the areas of communications, navigation, identification, and sensor fusion. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret. The CNI function includes both Secret and Unclassified elements. Sensitive elements of the CNI subsystems include:
(1) The VHF/UHF Voice and Data (Plain and Secure) Communication functionality includes air-to-air UHF/VHF voice and data, both clear and secure, to provide communications with other friendly and coalition aircraft, air-to-ground UHF voice to provide communications with ground sites, and intercommunication voice and tone alerts to provide communications between the avionics system and the pilot. UHF/VHF downlink of air vehicle status and maintenance information is provided to notify the ground crews of the amounts and types of stores, fuel, and other supplies or equipment needed to quickly turn the aircraft for the next mission. The system contains both Secret and Unclassified elements and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(2) The Tactical Air Navigation (TACAN) functionality provides operational modes to identify ground station and to provide bearing-to-station, slant range-to-ground station, bearing-to-airborne station and slant range to the nearest airborne station or aircraft. TACAN is not unique to the F–35 aircraft but is standard on most USAF aircraft. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(3) The Identification Friend or Foe Interrogator and Transponder Identification functionality consists of integrated Mark XII Identification Friend or Foe (IFF) transponder capability to provide identification of other friendly forces. The CNI system supports sensor fusion by supplying data from IFF interrogations and off-board sources through the intra-flight data link. The system contains both Secret and Unclassified elements and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(4) The Global Positioning System Navigation functionality includes the Global Positioning System (GPS) aided inertial navigation to provide high-quality positional navigation, and the Instrument Landing System (ILS)/Tactical Air Control and Navigation (TACAN) to provide navigation and landing cues within controlled airspace. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(5) The Multi-Function Advanced Data Link (MADL) is used specifically for communications between F–35 aircraft and has a very low probability of intercept, contributing to covert operations. The system contains both Secret and Unclassified elements and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(6) The Inertial Navigation System is an all-attitude, Ring Laser Gyro-based navigation system providing outputs of linear and angular acceleration, velocity, body angular rates, position, attitude (roll, pitch, and platform azimuth), magnetic and true heading, altitude, and time tags. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(7) The Radar Altimeter functionality is a module provided in the CNI system rack 3A and uses separate transmit and receive antennae. It measures and reports altitude, and altitude rate of change. Control data is transferred over to a configurable avionics interface card which translates the information to the F–35 aircraft computers. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
(8) The Instrument Landing System (ILS) measures, and reports azimuth course and alignment, elevation course
(9) The Tactical Data Links is a secure broadcast Tactical Digital Information Link (TADIL) used for real-time voice/data exchange for command and control, relative navigation, and Precise Position Location Identification (PPLI), providing Link-16 type capabilities. The system contains both Secret and Unclassified elements and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Secret.
g. The F–35 Autonomic Logistics Global Sustainment (ALGS) includes both Secret and Unclassified elements. It provides a fully integrated logistics management solution. ALGS integrates a number of functional areas, including supply chain management, repair, support equipment, engine support, and training. The ALGS infrastructure employs a state-of-the-art information system that provides real-time, decision-worthy information for sustainment decisions by flight line personnel. Prognostic health monitoring technology is integrated with the air system and is crucial to the predictive maintenance of vital components.
h. The F–35 Autonomic Logistics Information System (ALIS) includes both Secret and unclassified elements. The ALIS provides an intelligent information infrastructure that binds all of the key concepts of ALGS into an effective support system. ALIS establishes the appropriate interfaces among the F–35 Air Vehicle, the warfighter, the training system, government information technology (IT) systems, JSF operations, and supporting commercial enterprise systems. Additionally, ALIS provides a comprehensive tool for data collection and analysis, decision support, and action tracking.
i. The F–35 Training System includes both Secret and unclassified elements. The Training System includes several types of training devices, to provide for integrated training of both pilots and maintainers. The pilot training devices include a Full Mission Simulator (FMS) and Deployable Mission Rehearsal Trainer (DMRT). The maintainer training devices include an Aircraft Systems Maintenance Trainer (ASMT), Ejection System Maintenance Trainer (ESMT), and Weapons Loading Trainer (WLT). The F–35 Training System can be integrated, where both pilots and maintainers learn in the same Integrated Training Center (ITC). Alternatively, the pilots and maintainers can train in separate facilities (Pilot Training Center and Maintenance Training Center).
j. Weapons employment capability is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is Secret. Software (object code) is classified Secret. Sensitive elements include co-operative targeting.
k. Other Subsystems, Features, and Capabilities:
(1) The Low Observable Air Frame is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is Secret. Sensitive elements include: the Radar Cross Section and its corresponding plots, construction materials and fabrication.
(2) The Integrated Core Processor (ICP) Central Computer is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is Secret. Software (object code) is classified Secret. Sensitive elements include: F–35 Integrated Core Processor utilizing Commercial Off the Shelf (COTS) Hardware and Module Design to maximize growth and allow for efficient Management of DMS and Technology Insertion, if additional processing is needed, a second ICP will be installed in the space reserved for that purpose, more than doubling the current throughput and memory capacity.
(3) The F–35 Helmet Mounted Display System (HMDS) is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is Secret. Software (object code) is Secret. Sensitive elements include: HMDS consists of the Display Management Computer-Helmet, a helmet shell/display module, a quick disconnect integrated as part of the ejection seat, helmet trackers and tracker processing, day- and night-vision camera functions, and dedicated system/graphics processing. The HMDS provides a fully sunlight readable, bi-ocular display presentation of aircraft information projected onto the pilot's helmet visor. The use of a night vision camera integrated into the helmet eliminates the need for separate Night Vision Goggles (NVG). The camera video is integrated with EO and IR imaging inputs and displayed on the pilot's visor to provide a comprehensive night operational capability.
(4) The Pilot Life Support System is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is Secret. Software (object code) is Secret. Sensitive elements include: a measure of Pilot Chemical, Biological, and Radiological Protection through use of On Board Oxygen Generating System (OBOGS); and an escape system that provide additional protection to the pilot. OBOGS takes the Power and Thermal Management System (PTMS) air and enriches it by removing gases (mainly nitrogen) by adsorption, thereby increasing the concentration of oxygen in the product gas and supplying breathable air to the pilot.
(5) The Off-Board Mission Support System is Secret and contains technology representing the latest state-of-the-art in several areas. Information on performance and inherent vulnerabilities is Secret. Software (object code) is Secret. Sensitive elements include: mission planning, mission briefing, maintenance/intelligence/tactical debriefing, sensor/algorithm planning, EW system reprogramming, data debrief, etc.
l. Publications: Manuals are considered Secret as they contain information on aircraft/system performance and inherent vulnerabilities.
2. The JSF Reprogramming Center is classified Secret and contains technology representing the latest state-of-the-art in several areas. This hardware/software facility provides a means to update JSF electronic warfare databases. Sensitive elements include: EW software databases and tools to modify these databases.
3. If a technologically advanced adversary were to obtain knowledge of the specific hardware and software elements, the information could be used to develop countermeasures that might reduce weapon system effectiveness or be used in the development of a system with similar or advanced capabilities.
Defense Security Cooperation Agency, Department of Defense.
Notice.
The Department of Defense is publishing the unclassified text of a section 36(b)(1) arms sales notification. This is published to fulfill the requirements of section 155 of Public Law 104–164 dated July 21, 1996.
Ms. B. English, DSCA/DBO/CFM, (703) 601–3740.
The following is a copy of a letter to the Speaker of the House of Representatives, Transmittals 13–11 with attached transmittal, policy justification, and Sensitivity of Technology.
(i)
(ii)
(iii)
Also included are the Advanced Display Core Processor II, Joint Mission Planning System, various support equipment items, GEM–V GPS airborne receiver module, and communication security, software development/integration, spares and repair parts, personnel training and training equipment, publications and technical documents, U.S. Government and contract engineering and logistical personnel services, and other related elements of logistics and program support.
(iv)
(v)
(vi)
(vii)
(viii)
* As defined in Section 47(6) of the Arms Export Control Act.
The Republic of Korea has requested a possible hybrid case in support of (60) F–15 Silent Eagle aircraft being procured via Direct Commercial Sales (DCS). The proposed sale will include 60 Active Electronically Scanned Array Radar (AESA) radar sets, 60 Digital Electronic Warfare Systems (DEWS), 60 AN/AAQ–33 Sniper Targeting Systems, 60 AN/AAS–42 Infrared Search and Track (IRST) Systems, 132 Ultra High Frequency/Very High Frequency (UHF/VHF) secure radio with HAVE QUICK II, 69 Link-16 Terminals and spares, the Advanced Display Core Processor II, Joint Mission Planning System, various support equipment items, GEM–V GPS airborne receiver module, and communication security; software development/integration, spares and repair parts, personnel training and training equipment, publications and technical documents, U.S. Government and contract engineering and logistical personnel services, and other related elements of logistics and program support. The estimated cost is $2.408 billion.
This proposed sale will contribute to the foreign policy goals and national security objectives of the United States by meeting the legitimate security and defense needs of an ally and partner nation. The Republic of Korea continues to be an important force for peace, political stability, and economic progress in North East Asia.
The proposed sale will augment Korea's operational aircraft inventory and enhance its air-to-air and air-to-ground self-defense capability, provide it with a credible defense capability to deter aggression in the region, and ensure interoperability with U.S. forces. The Republic of Korea Air Force's F–4 aircraft will be decommissioned as F–15SEs are added to the inventory. Korea will have no difficulty absorbing this additional equipment and support into its inventory.
The proposed sale of equipment and support will not negatively alter the basic military balance in the region.
Implementation of this proposed sale will require multiple trips to Korea involving U.S. Government and contractor representatives for technical reviews and support, program management, and training over a period of 15 years.
The prime contractor will be The Boeing Corporation in St Louis, Missouri. This proposal is being offered in the context of a competition. If the proposal is accepted, it is expected that offset agreements will be required.
There will be no adverse impact on U.S. defense readiness resulting from this proposed sale.
(vii)
1. This Direct Commercial Sale (DCS)/Foreign Military Sale (FMS) Hybrid sale will involve the release of sensitive technology to the Republic of Korea (ROK). The F–15SE weapons system is classified up to Secret. The F–15SE aircraft (DCS) uses the F–15E airframe and features advanced avionics and other technologically sensitive systems. The F-l5SE will contain the General Electric F110–GE–129E engine (DCS), AN/APG–63(v)3 Active Electronically Scanned Array (AESA) radar (FMS), internal and external electronic warfare and self-protection equipment (FMS), Identification Friend or Foe (IFF) system (FMS), operational flight program, and software computer programs.
2. Sensitive and/or classified (up to Secret) elements of the proposed F–15SE include hardware, accessories, components, and associated software: APG–63(v)3 AESA, Digital Electronic Warfare Suite (DEWS), the AN/AAQ–33 SNIPER targeting system, Infrared Search and Track system (IRST), Link-16 Terminals, and Ultra High Frequency Very High Frequency (UHF/VHF) secure radio. Additional sensitive areas include operating manuals and maintenance technical orders containing performance information, operating and test procedures, and other information related to support operations and repair. The hardware, software, and data identified are classified to protect vulnerabilities, design and performance parameters and other similar critical information.
3. The Active Electronically Scanned Array (AESA) radar is the latest model of the F–15E radar. This model contains digital technology, including high processor and transmitter power, sensitive receiver electronics, and Synthetic Aperture Radar (SAR), which creates high resolution radar ground maps. This radar also incorporates Non Cooperative Threat Recognition (NCTR) to aid in aircraft identification. The complete hardware is classified Confidential; major components and subsystems are classified Confidential; software is classified Secret; and technical data and documentation are classified up to Secret.
4. The Digital Electronic Warfare Suite (DEWS) provides passive radar warning, wide spectrum RF jamming,
5. The AN/AAQ–33 SNIPER Targeting System is Unclassified but contains technology representing the latest state-of-the-art in several areas. This pod is a third generation infrared and electro-optical pod capable of full motion video downlink. Information on performance and inherent vulnerabilities is classified Secret. Software (object code) is classified Confidential. Sensitive elements include the forward looking infrared (FLIR) sensors, and Electronic Counter Countermeasures features that increase capability in a jamming environment.
6. The AN/AAS–42 Infrared Search and Track (IRST) system is a long-wave, high resolution, passive, infrared sensor system that searches and detects heat sources within its field of regard. The AN/AAS–42 is classified Confidential, components and subsystems range from Unclassified to Confidential, and technical data and other documentation are classified up to Secret.
7. Link-16 command, control, communications, and intelligence (C3I) system incorporating high capacity, jam-resistant, digital communication links for exchange of near real-time tactical information, including both data and voice, among air, ground, and sea elements.
8. The Ultra High Frequency/Very High Frequency (UHF/VHF) secure radio with HAVE QUICK II is voice communications radio system that can operate in either normal, secure, and/or jam resistant modes. It can employ cryptographic technology that is classified Secret. Classified elements include operating characteristics, parameters, technical data, and keying material.
9. If a technologically advanced adversary were to obtain knowledge of the specific hardware and software, the information could be used to develop countermeasures, which might reduce weapon system effectiveness or be used in the development of a system with similar or advanced capabilities.
Office of Postsecondary Education (OPE), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before June 17, 2013.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
Electronically mail
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.
Office of Postsecondary Education (OPE), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before June 17, 2013.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
Electronically mail
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.
Office of Special Education and Rehabilitative Services, Department of Education.
Notice.
Technical Assistance and Dissemination to Improve Services and Results for Children With Disabilities—Center on Dispute Resolution.
Notice inviting applications for a new award for fiscal year (FY) 2013.
This priority is:
IDEA includes procedural safeguards that are designed to protect the rights of children with disabilities and their parents and to provide parents with mechanisms for resolving, at the earliest point in time, disputes with those who provide services to children with disabilities (State educational agencies (SEAs), local educational agencies (LEAs), schools, Part C State lead agencies, and early intervention service (EIS) providers). The procedural safeguards include the opportunity to seek a timely resolution of disputes about any matter relating to the provision of a free appropriate public education to an eligible child or of appropriate early intervention services to infants and toddlers with disabilities. Thus, IDEA encourages constructive relationships between parents of children with disabilities and those who provide services to children with disabilities by facilitating open communication between the parents and these entities and encouraging early resolution of disputes so that disagreements do not escalate and become adversarial. IDEA's dispute resolution procedures include provisions for State complaints, mediation, due process complaints and due process hearings, and resolution sessions, as described below.
Over the past seven years, data from State Performance Plans (SPPs) and Annual Performance Reports (APRs) submitted to the Office of Special Education Programs (OSEP) show a steady decline in the number of IDEA Part B due process hearings held across the country, down 68 percent since FY 2004. At the same time, SEAs and Part C State lead agencies are reporting an increase in the use of informal early resolution practices that have been shown to reduce the need for dispute resolution and facilitate early resolution of disputes. Examples of early resolution practices include training in conflict resolution, which is designed to equip individuals with skills to better communicate and negotiate their positions and interests, (Henderson, 2008), and IEP and IFSP facilitation.
Since 1998, OSEP has funded a technical assistance (TA) center to support States' implementation of timely and effective dispute resolution processes. (For further information on the work of the current center, please see the following Web site:
The Department believes it is important to continue to fund a TA center that provides SEAs and Part C State lead agencies with resources that can help them effectively implement a range of dispute resolution options to ensure that the trend toward early, less costly, and less adversarial dispute resolution continues. SEAs and Part C State lead agencies also need information on how to collect and use data from dispute resolution systems to improve compliance with IDEA requirements. In addition, continued funding of a TA center on dispute resolution that works directly with OSEP-funded parent technical assistance centers (PTACs) will help ensure that parents and families have access to information on how to resolve their disagreements in positive and constructive ways.
The purpose of this priority is to fund a cooperative agreement to support the establishment and operation of a Center on Dispute Resolution designed to produce, at a minimum, the following outcomes: (1) An increased capacity of SEAs and Part C State lead agencies to support local implementation of effective early resolution practices to resolve disputes and thereby decrease requests for State complaints and due process hearings; (2) an increased body of knowledge on strategies for collecting, reporting, and using high-quality data on dispute resolution; (3) an increased body of knowledge on exemplary practices for parents and families to resolve disputes in positive and constructive ways; (4) an improved ability of SEAs and Part C State lead agencies to implement a range of dispute resolution options, including methods of dispute resolution required under IDEA and early resolution practices; (5) an improved capacity of OSEP-funded PTACs to provide technical assistance to OSEP-funded parent centers on the range of effective dispute resolution options; and (6) an analysis of current information on State and national trends and other data about dispute resolution to determine the extent to which SEAs and Part C State lead agencies have: (a) Met the required timelines when resolving State complaints and issuing due process hearing decisions; (b) used resolution meetings and mediation to successfully resolve disputes between parents and LEAs or EIS providers; and (c) implemented effective methods of early dispute resolution.
In addition to these programmatic requirements, to be considered for funding under this absolute priority, applicants must meet the application and administrative requirements contained in this priority. OSEP encourages innovative approaches to meet these requirements, which are as follows:
(a) Demonstrate, in the narrative section of the application under “Significance of the Project,” how the proposed project will—
(1) Address the training and information needs of SEAs, Part C State lead agencies, and parents and families to resolve disputes arising from programs under Part B and Part C of IDEA. To address this requirement the applicant must—
(i) Present applicable national and State data demonstrating the training and information needs of SEAs, Part C State lead agencies, and parents and families to resolve disputes;
(ii) Demonstrate knowledge of current educational issues and policy initiatives in dispute resolution (e.g., the implementation and effectiveness of IEP/IFSP facilitation); and
(iii) Present information about the implementation and effectiveness of current dispute resolution systems in SEAs and Part C State lead agencies.
(2) Result in early resolution of disputes and improved compliance with IDEA dispute resolution requirements.
(b) Demonstrate, in the narrative section of the application under
(1) Ensure equal access and treatment for members of groups (e.g., race, color, national origin, language, linguistic background, gender, age, or disability) that traditionally have not engaged in, or have been underrepresented in accessing, dispute resolution options. To meet this requirement, the applicant must describe the process that will be used to—
(i) Identify the needs of the intended recipients (i.e., SEAs, Part C State lead agencies, and PTACs) for technical assistance and information; and
(ii) Ensure that services and products meet the needs of the intended recipients (e.g., creating materials in formats and languages accessible to the stakeholders served by the intended recipients).
(2) Meet its goals, objectives, and outcomes. To meet this requirement, the applicant must provide—
(i) Measurable intended project outcomes; and
(ii) The theory of action (i.e., a logic model) on how the proposed project will achieve the project outcomes.
(3) Use a conceptual framework to guide the development of project plans and activities, describing any underlying concepts, assumptions, expectations, beliefs, or theories, as well as the presumed relationship or linkages among these variables, and any empirical support for this framework;
(4) Be based on current research and evidence-based practices. To meet this requirement, the applicant must describe—
(i) The current research on the effectiveness of dispute resolution options and practices;
(ii) The current research about adult learning principles and how this information will be used to provide training and technical assistance to the intended recipients on implementing effective dispute resolution systems; and
(iii) The process the proposed project will use to incorporate current research and evidence-based practices in the development and delivery of its products and services.
(5) Develop products and provide services that are of sufficient quality, intensity, and duration to achieve the outcomes of the proposed project. To address this requirement, the applicant must describe—
(i) Its proposed activities to identify and expand the knowledge base in dispute resolution and early resolution practices;
(ii) Its proposed approach to universal, general TA,
(iii) Its proposed approach to targeted, specialized TA,
(iv) Its proposed approach to intensive, sustained TA,
(A) Its proposed plan for assisting SEAs, Part C State lead agencies, and PTACs to build training systems that include professional development based on evidence-based adult learning principles and coaching; and
(B) Its proposed plan for supporting SEAs, Part C State lead agencies, and PTACs in their work with hearing officers, IEP/IFSP Team facilitators, or other dispute resolution personnel, as well as families and personnel at each level of the education or early intervention system (e.g., regional TA providers, school districts, schools, service coordinators, and related service and EIS providers and personnel), to ensure that there is effective communication among these groups and that there are systems in place to support the use of a range of dispute resolution procedures and practices.
(6) Develop products and implement services to maximize the efficiency of an SEA's or Part C State lead agency's dispute resolution system. To address this requirement, the applicant must describe—
(i) How the proposed project will use technology to achieve the intended outcomes;
(ii) With whom the proposed project will collaborate and the intended outcomes of this collaboration; and
(iii) How the proposed project will leverage non-project resources to achieve the proposed project outcomes.
(c) Demonstrate, in the narrative section of the application under “Quality of the Evaluation Plan,” how—
(1) The proposed project will collect and analyze data related to specific and measurable goals, objectives, and outcomes of the project. To address this requirement, the applicant must describe—
(i) Proposed evaluation methodologies, including instruments, data collection methods, and possible analyses;
(ii) Proposed standards or targets for determining effectiveness; and
(iii) Proposed methods for collecting data on implementation supports and fidelity of implementation.
(2) The proposed project will use the evaluation results to examine the effectiveness of the project's implementation strategies and the progress toward achieving intended outcomes; and
(3) The methods of evaluation will produce quantitative and qualitative data that demonstrate whether the project achieved the intended outcomes.
(d) Demonstrate, in the narrative section of the application under “Adequacy of Project Resources,” how—
(1) The proposed project will encourage applications for employment from persons who are members of groups that have traditionally been underrepresented based on race, color, national origin, language/linguistic background, gender, age, or disability, as appropriate;
(2) The proposed key project personnel, consultants, and subcontractors have the qualifications and experience to carry out the proposed activities and achieve the project's intended outcomes;
(3) The applicant and any key partners have adequate resources to carry out the proposed activities; and
(4) The proposed costs are reasonable in relation to the anticipated results and benefits.
(e) Demonstrate, in the narrative section of the application under “Quality of the Management Plan,” how—
(1) The proposed management plan will ensure that the project's intended outcomes will be achieved on time and within budget. To address this requirement, the applicant must describe—
(i) Clearly defined responsibilities for key project personnel, consultants, and subcontractors, as appropriate; and
(ii) Timelines and milestones for accomplishing the project tasks;
(2) Key project personnel and any consultants and subcontractors who will be allocated to the project and the appropriateness and adequacy of these time allocations to achieve the project's intended outcomes;
(3) The proposed management plan will ensure that the products and services provided are of high quality; and
(4) The proposed project will benefit from a diversity of perspectives, including families, EIS providers, educators, related service providers, TA providers, researchers, and policy makers, among others, in its development and operation.
(f) Meet the following program requirements—
(1) Include in Appendix A a logic model that depicts, at a minimum, the goals, activities, outputs, and outcomes of the proposed project. A logic model communicates how a project will achieve its outcomes and provides a framework for both the formative and summative evaluations of the project.
The following Web sites provide more information on logic models:
(2) Include in Appendix A a visual representation of the conceptual framework, if a visual representation is developed;
(3) Include in Appendix A a person-loading chart and timelines, as appropriate, to illustrate the management plan described in the narrative;
(4) Include in the budget attendance at the following:
(i) A one and one-half day kick-off meeting to be held in Washington, DC, after receipt of the award, and an annual planning meeting held in Washington, DC, with the OSEP project officer and other relevant staff during each subsequent year of the project period.
Within 30 days of receipt of the award, a post-award teleconference must be held between the OSEP project officer and the grantee's project director or other authorized representative;
(ii) A two and one-half day project directors' conference in Washington, DC, during each year of the project period;
(iii) Two, two-day trips annually to present at Department briefings, Department-sponsored conferences, and other meetings, as requested by OSEP; and
(iv) A one-day intensive review meeting that will be held during the last half of the second year of the project period.
(5) Include in the budget a line item for an annual set-aside of five percent of the grant amount to support emerging needs that are consistent with the proposed project's intended outcomes, as those needs are identified in consultation with OSEP.
With approval from the OSEP project officer, the project must reallocate any remaining funds from this annual set-aside no later than the end of the third quarter of each budget period; and
(6) Maintain a Web site that meets government or industry-recognized standards for accessibility.
In deciding whether to continue funding the project for the fourth and fifth years, the Secretary will consider the requirements of 34 CFR 75.253(a), as well as—
(a) The recommendation of a review team consisting of experts selected by the Secretary. This review will be conducted during a one-day intensive meeting in Washington, DC, that will be held during the last half of the second year of the project period;
(b) The timeliness and effectiveness with which all requirements of the negotiated cooperative agreement have been or are being met by the project; and
(c) The quality, relevance, and usefulness of the project's activities and products and the degree to which the project's activities and products are aligned with the project's objectives and likely to result in the project achieving its proposed outcomes.
The regulations in 34 CFR part 79 apply to all applicants except federally recognized Indian tribes.
The regulations in 34 CFR part 86 apply to institutions of higher education (IHEs) only.
Contingent upon the availability of funds and the quality of applications, we may make additional awards in FY 2014 from the list of unfunded applicants from this competition.
The Department is not bound by any estimates in this notice.
1.
2.
3.
(b) Each applicant and grant recipient funded under this program must involve individuals with disabilities or parents of individuals with disabilities ages birth through 26 in planning, implementing, and evaluating the project (see section 682(a)(1)(A) of IDEA).
1.
You can contact ED Pubs at its Web site, also:
If you request an application from ED Pubs, be sure to identify this competition as follows: CFDA number 84.326X.
Individuals with disabilities can obtain a copy of the application package in an accessible format (e.g., braille, large print, audiotape, or compact disc) by contacting the person or team listed under
2.
Page Limit: The application narrative (Part III of the application) is where you, the applicant, address the selection criteria that reviewers use to evaluate your application. You must limit Part III to the equivalent of no more than 70 pages using the following standards:
• A “page” is 8.5″ x 11″, on one side only, with 1″ margins at the top, bottom, and both sides.
• Double space (no more than three lines per vertical inch) all text in the application narrative, including titles, headings, footnotes, quotations, references, and captions, as well as all text in charts, tables, figures, and graphs.
• Use a font that is either 12 point or larger or no smaller than 10 pitch (characters per inch).
• Use one of the following fonts: Times New Roman, Courier, Courier New, or Arial. An application submitted in any other font (including Times Roman or Arial Narrow) will not be accepted.
The page limit does not apply to Part I, the cover sheet; Part II, the budget section, including the narrative budget justification; Part IV, the assurances and certifications; or the one-page abstract, the resumes, the bibliography, or the letters of support. However, the page limit does apply to all of Part III.
We will reject your application if you exceed the page limit; or if you apply other standards and exceed the equivalent of the page limit.
3.
Applications for grants under this competition must be submitted electronically using the Grants.gov Apply site (Grants.gov). For information (including dates and times) about how to submit your application electronically, or in paper format by mail or hand delivery if you qualify for an exception to the electronic submission requirement, please refer to section IV.7.
We do not consider an application that does not comply with the deadline requirements.
Individuals with disabilities who need an accommodation or auxiliary aid in connection with the application process should contact the person listed under
4.
5.
6.
a. Have a Data Universal Numbering System (DUNS) number and a Taxpayer Identification Number (TIN);
b. Register both your DUNS number and TIN with the Central Contractor Registry (CCR)—and, after July 24, 2012, with the System for Award Management (SAM), the Government's primary registrant database;
c. Provide your DUNS number and TIN on your application; and
d. Maintain an active CCR or SAM registration with current information while your application is under review by the Department and, if you are awarded a grant, during the project period.
You can obtain a DUNS number from Dun and Bradstreet. A DUNS number can be created within one business day.
If you are a corporate entity, agency, institution, or organization, you can obtain a TIN from the Internal Revenue Service. If you are an individual, you can obtain a TIN from the Internal Revenue Service or the Social Security Administration. If you need a new TIN, please allow 2–5 weeks for your TIN to become active.
The CCR or SAM registration process may take five or more business days to complete. If you are currently registered with the CCR, you may not need to make any changes. However, please make certain that the TIN associated with your DUNS number is correct. Also note that you will need to update your registration annually. This may take three or more business days to complete. Information about SAM is available at SAM.gov.
In addition, if you are submitting your application via Grants.gov, you must (1) be designated by your organization as an Authorized Organization Representative (AOR); and (2) register yourself with Grants.gov as an AOR. Details on these steps are outlined at the following Grants.gov Web page:
7.
a.
Applications for grants under the Center on Dispute Resolution
We will reject your application if you submit it in paper format unless, as described elsewhere in this section, you qualify for one of the exceptions to the electronic submission requirement
You may access the electronic grant application for the Center on Dispute Resolution at www.Grants.gov. You must search for the downloadable application package for this competition by the CFDA number. Do not include the CFDA number's alpha suffix in your search (e.g., search for 84.326, not 84.326X).
Please note the following:
• When you enter the Grants.gov site, you will find information about submitting an application electronically through the site, as well as the hours of operation.
• Applications received by Grants.gov are date and time stamped. Your application must be fully uploaded and submitted and must be date and time stamped by the Grants.gov system no later than 4:30:00 p.m., Washington, DC time, on the application deadline date. Except as otherwise noted in this section, we will not accept your application if it is received—that is, date and time stamped by the Grants.gov system—after 4:30:00 p.m., Washington, DC time, on the application deadline date. We do not consider an application that does not comply with the deadline requirements. When we retrieve your application from Grants.gov, we will notify you if we are rejecting your application because it was date and time stamped by the Grants.gov system after 4:30:00 p.m., Washington, DC time, on the application deadline date.
• The amount of time it can take to upload an application will vary depending on a variety of factors, including the size of the application and the speed of your Internet connection. Therefore, we strongly recommend that you do not wait until the application deadline date to begin the submission process through Grants.gov.
• You should review and follow the Education Submission Procedures for submitting an application through Grants.gov that are included in the application package for this competition to ensure that you submit your application in a timely manner to the Grants.gov system. You can also find the Education Submission Procedures pertaining to Grants.gov under News and Events on the Department's G5 system home page at
• You will not receive additional point value because you submit your application in electronic format, nor will we penalize you if you qualify for an exception to the electronic submission requirement, as described elsewhere in this section, and submit your application in paper format.
• You must submit all documents electronically, including all information you typically provide on the following forms: the Application for Federal Assistance (SF 424), the Department of Education Supplemental Information for SF 424, Budget Information—Non-Construction Programs (ED 524), and all necessary assurances and certifications.
• You must upload any narrative sections and all other attachments to your application as files in a PDF (Portable Document) read-only, non-modifiable format. Do not upload an interactive or fillable PDF file. If you upload a file type other than a read-only, non-modifiable PDF or submit a password-protected file, we will not review that material. Additional, detailed information on how to attach files is in the application instructions.
• Your electronic application must comply with any page-limit requirements described in this notice.
• After you electronically submit your application, you will receive from Grants.gov an automatic notification of receipt that contains a Grants.gov tracking number. (This notification indicates receipt by Grants.gov only, not receipt by the Department.) The Department then will retrieve your application from Grants.gov and send a second notification to you by email. This second notification indicates that the Department has received your application and has assigned your application a PR/Award number (an ED-specified identifying number unique to your application).
• We may request that you provide us original signatures on forms at a later date.
If you are prevented from electronically submitting your application on the application deadline date because of technical problems with the Grants.gov system, we will grant you an extension until 4:30:00 p.m., Washington, DC time, the following business day to enable you to transmit your application electronically or by hand delivery. You also may mail your application by following the mailing instructions described elsewhere in this notice.
If you submit an application after 4:30:00 p.m., Washington, DC time, on the application deadline date, please contact the person listed under
The extensions to which we refer in this section apply only to the unavailability of, or technical problems with, the Grants.gov system. We will not grant you an extension if you failed to fully register to submit your application to Grants.gov before the application deadline date and time or if the technical problem you experienced is unrelated to the Grants.gov system.
• You do not have access to the Internet; or
• You do not have the capacity to upload large documents to the Grants.gov system;
• No later than two weeks before the application deadline date (14 calendar days or, if the fourteenth calendar day before the application deadline date falls on a Federal holiday, the next business day following the Federal holiday), you mail or fax a written statement to the Department, explaining which of the two grounds for an
If you mail your written statement to the Department, it must be postmarked no later than two weeks before the application deadline date. If you fax your written statement to the Department, we must receive the faxed statement no later than two weeks before the application deadline date.
Address and mail or fax your statement to: Tina Diamond, U.S. Department of Education, 400 Maryland Avenue SW., room 4094, Potomac Center Plaza (PCP), Washington, DC 20202–2600. FAX: (202) 245–7617.
Your paper application must be submitted in accordance with the mail or hand delivery instructions described in this notice.
b.
If you qualify for an exception to the electronic submission requirement, you may mail (through the U.S. Postal Service or a commercial carrier) your application to the Department. You must mail the original and two copies of your application, on or before the application deadline date, to the Department at the following address: U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.326X), LBJ Basement Level 1, 400 Maryland Avenue SW., Washington, DC 20202–4260.
You must show proof of mailing consisting of one of the following:
(1) A legibly dated U.S. Postal Service postmark.
(2) A legible mail receipt with the date of mailing stamped by the U.S. Postal Service.
(3) A dated shipping label, invoice, or receipt from a commercial carrier.
(4) Any other proof of mailing acceptable to the Secretary of the U.S. Department of Education.
If you mail your application through the U.S. Postal Service, we do not accept either of the following as proof of mailing:
(1) A private metered postmark.
(2) A mail receipt that is not dated by the U.S. Postal Service.
If your application is postmarked after the application deadline date, we will not consider your application.
The U.S. Postal Service does not uniformly provide a dated postmark. Before relying on this method, you should check with your local post office.
c.
If you qualify for an exception to the electronic submission requirement, you (or a courier service) may deliver your paper application to the Department by hand. You must deliver the original and two copies of your application by hand, on or before the application deadline date, to the Department at the following address: U.S. Department of Education, Application Control Center, Attention: (CFDA Number 84.326X), 550 12th Street SW., Room 7041, Potomac Center Plaza, Washington, DC 20202–4260.
The Application Control Center accepts hand deliveries daily between 8:00 a.m. and 4:30:00 p.m., Washington, DC time, except Saturdays, Sundays, and Federal holidays.
(1) You must indicate on the envelope and—if not provided by the Department—in Item 11 of the SF 424 the CFDA number, including suffix letter, if any, of the competition under which you are submitting your application; and
(2) The Application Control Center will mail to you a notification of receipt of your grant application. If you do not receive this notification within 15 business days from the application deadline date, you should call the U.S. Department of Education Application Control Center at (202) 245–6288.
1.
2.
In addition, in making a competitive grant award, the Secretary also requires various assurances including those applicable to Federal civil rights laws that prohibit discrimination in programs or activities receiving Federal financial assistance from the Department of Education (34 CFR 100.4, 104.5, 106.4, 108.8, and 110.23).
3.
4.
1.
If your application is not evaluated or not selected for funding, we notify you.
2.
We reference the regulations outlining the terms and conditions of an award in the
3.
(b) At the end of your project period, you must submit a final performance report, including financial information, as directed by the Secretary. If you receive a multi-year award, you must submit an annual performance report that provides the most current performance and financial expenditure information as directed by the Secretary under 34 CFR 75.118. The Secretary may also require more frequent performance reports under 34 CFR 75.720(c). For specific requirements on reporting, please go to
4.
Grantees will be required to report information on their project's performance in annual reports to the Department (34 CFR 75.590).
5.
Tina Diamond, U.S. Department of Education, 400 Maryland Avenue SW., Room 4094, PCP, Washington, DC 20202–2600. Telephone: (202) 245–6674.
If you use a TDD or a TTY, call the Federal Relay Service (FRS), toll free, at 1–800–877–8339.
You may also access documents of the Department published in the
Department of Energy.
Notice of Open Meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Oak Ridge Reservation. The Federal Advisory Committee Act (Pub. L. 92–463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Wednesday, May 8, 2013, 6:00 p.m.
Department of Energy Information Center, Office of Science and Technical Information, 1 Science.gov Way, Oak Ridge, Tennessee 37830.
Melyssa P. Noe, Federal Coordinator, Department of Energy Oak Ridge Operations Office, P.O. Box 2001, EM–90, Oak Ridge, TN 37831. Phone (865) 241–3315; Fax (865) 576–0956 or email:
Purpose of the Board: The purpose of the Board is to make recommendations to DOE–EM and site management in the areas of environmental restoration, waste management, and related activities.
Tentative Agenda:
• Welcome and Announcements
• Comments from the Deputy Designated Federal Officer
• Comments from the DOE, Tennessee Department of Environment and Conservation, and Environmental Protection Agency Liaisons
• Public Comment Period
• Presentation on the National Environmental Management Program
• Additions/Approval of Agenda
• Motions/Approval of April 10, 2013 minutes
• Status of Recommendations with DOE
• Committee Reports
• Federal Coordinator Report
• Adjourn
Office of Science, Department of Energy .
Notice of partially-closed meeting.
This notice sets forth the schedule and summary agenda for a partially closed meeting of the President's Council of Advisors on Science and Technology (PCAST), and describes the functions of the Council. Notice of this meeting is required under the Federal Advisory Committee Act (FACA), 5 U.S.C., App. 2.
Friday, May 3, 2013; 9:00 a.m.—12:30 p.m.
National Academy of Sciences (in the Lecture Room), 2101 Constitution Avenue NW, Washington, DC.
Information regarding the meeting agenda, time, location, and how to register for the meeting is available on the PCAST Web site at:
The President's Council of Advisors on Science and Technology (PCAST) is an advisory group of the nation's leading scientists and engineers, appointed by the President to augment the science and technology advice available to him from inside the White House and from cabinet departments and other Federal agencies. See the Executive Order at
The public comment period for this meeting will take place on May 3, 2013, at a time specified in the meeting agenda posted on the PCAST Web site at
Please note that because PCAST operates under the provisions of FACA, all public comments and/or presentations will be treated as public documents and will be made available for public inspection, including being posted on the PCAST Web site.
Department of Energy.
Notice of open meetings.
This notice announces two meetings of the National Coal Council (NCC). The Federal Advisory Committee
Thursday, May 16, 2013, 4:00 p.m. to 5:00 p.m. Friday, May 17, 2013, 9:00 a.m. to 12:00 p.m.
Fairmont Hotel, 2401 M Street NW., Washington, DC 20037.
Dr. Robert J. Wright, U.S. Department of Energy, 4G–036/Forrestal Building, 1000 Independence Avenue SW., Washington, DC 20585–1290; Telephone: 202–586–0429.
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following open access transmission tariff filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, and service can be found at:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Environmental Protection Agency (EPA).
Notice of the Availability of Funds.
EPA's Office of Brownfields and Land Revitalization (OBLR) plans to make available approximately $6 million to provide supplemental funds to Revolving Loan Fund capitalization grants previously awarded competitively under section 104(k)(3) of the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), 42 U.S.C. 9604(k)(3). Brownfields Cleanup Revolving Loan Fund (BCRLF) pilots awarded under section 104(d)(1) of CERCLA that have not transitioned to section 104(k)(3) grants are not eligible to apply for these funds. EPA will consider awarding supplemental funding only to RLF grantees who have demonstrated an ability to deliver programmatic results by making at least one loan or subgrant. The award of these funds is based on the criteria described at CERCLA 104(k)(4)(A)(ii) .
The Agency is now accepting requests for supplemental funding from RLF grantees. Requests for funding must be submitted to the appropriate EPA Regional Brownfields Coordinator (listed below) by May 20, 2013. Funding requests for hazardous substances and/or petroleum funding will be accepted. Specific information on submitting a request for RLF supplemental funding is described below and additional information may be obtained by contacting the EPA Regional Brownfields Coordinator.
This action is effective April 18, 2013.
A request for supplemental funding must be in the form of a letter addressed to the appropriate Regional Brownfields Coordinator (see listing below) with a copy to Ted Lanzano,
Ted Lanzano, U.S. EPA, (303) 312–6596 or the appropriate Brownfields Regional Coordinator.
The Small Business Liability Relief and Brownfields Revitalization Act added section 104(k) to CERCLA to authorize federal financial assistance for brownfields revitalization, including grants for assessment, cleanup and job training. Section 104(k) includes a provision for the EPA to, among other things, award grants to eligible entities to capitalize Revolving Loan Funds and to provide loans and subgrants for brownfields cleanup. Section 104(k)(4)(A)(ii) authorizes EPA to make additional grant funds available to RLF grantees for any year after the year for which the initial grant is made (noncompetitive RLF supplemental funding) taking into consideration:
(I) The number of sites and number of communities that are addressed by the revolving loan fund;
(II) The demand for funding by eligible entities that have not previously received a grant under this subsection;
(III) The demonstrated ability of the eligible entity to use the revolving loan fund to enhance remediation and provide funds on a continuing basis; and
(IV) Such other similar factors as the [Agency] considers appropriate to carry out this subsection.
In order to be considered for supplemental funding, grantees must demonstrate that they have expended existing funds and that they have a clear plan for quickly expending requested additional funds. Grantees must demonstrate that they have made at least one loan or subgrant prior to applying for this supplemental funding and have significantly depleted existing available funds. For FY2013, EPA defines “significantly depleted funds” as any grant where $250,000–$300,000 or less remains uncommitted for single entities and $300,000–$400,000 or less remains uncommitted for states/large coalitions. Additionally, the RLF recipient must have demonstrated a need for supplemental funding based on, among other factors, the number of sites that will be addressed; demonstrated the ability to make loans and subgrants for cleanups that can be started and completed expeditiously (i.e., “shovel-ready” projects) and will lead to redevelopment; demonstrated the existence of additional leveraged funds to complete the project in a timely manner and move quickly from cleanup to redevelopment, including the use of tax incentives such as new market tax credits, direct funding or other resources to advance the project to
Environmental Protection Agency (EPA).
Notice of a public meeting.
The United States Environmental Protection Agency's (EPA) Environmental Financial Advisory Board (EFAB) will hold a public meeting on May 15–16, 2013. EFAB is an EPA advisory committee chartered under the Federal Advisory Committee Act (FACA) to provide advice and recommendations to EPA on creative approaches to funding environmental programs, projects, and activities.
The purpose of this meeting is to hear from informed speakers on environmental finance issues, proposed legislation, and EPA priorities; to discuss activities and progress with regard to current EFAB work projects; and to consider recent requests for assistance from EPA offices.
Environmental finance discussions are expected on the following topics: clean air technology; tribal environmental programs; transit-oriented development in sustainable communities, energy efficiency/green house gas emissions reduction; drinking water pricing and infrastructure investment; and green infrastructure.
The meeting is open to the public; however, seating is limited. All members of the public who wish to attend the meeting must register in advance, no later than Friday, May 3, 2013.
The full board meeting will be held on Wednesday, May 15, 2013 from 1:30 p.m. to 5 p.m., Eastern Time and Thursday, May 16, 2013 from 9–5 p.m., Eastern Time.
Potomac Yard Two, North Entrance, Room 4120, 2733 Crystal Drive, Arlington, VA 22202.
Environmental Protection Agency (EPA).
Notice of a final decision on a no migration petition reissuance.
Notice is hereby given that a reissuance of an exemption to the land disposal Restrictions, under the 1984 Hazardous and Solid Waste
This action is effective as of February 21, 2013.
Copies of the petition for reissuance and all pertinent information relating thereto are on file at the following location: Environmental Protection Agency, Region 6, Water Quality Protection Division, Source Water Protection Branch (6WQ–S), 1445 Ross Avenue, Dallas, Texas 75202–2733.
Philip Dellinger, Chief Ground Water/UIC Section, EPA—Region 6, telephone (214) 665–8324.
Farm Credit System Insurance Corporation.
Policy statement.
The Farm Credit System Insurance Corporation (Corporation or FCSIC) announces that it has given final approval to a new “Policy Statement Concerning Assistance,” which replaces the Corporation's existing “Policy Statement Concerning Stand-Alone Assistance.” The new policy statement provides additional transparency concerning the Corporation's authority to provide assistance and how the least-cost test might be performed. This policy statement also includes enhanced criteria of what is to be included in assistance proposals, and a new section discussing assistance agreements.
Wade Wynn, Senior Risk Analyst, and James M. Morris, General Counsel, Farm Credit System Insurance Corporation, 1501 Farm Credit Drive, McLean, Virginia 22102, (703) 883–4380, TDD (703) 883–4390.
The Corporation, in its sole discretion, is authorized under section 5.61(a) of the Farm Credit Act of 1971, as amended (Act),
The Corporation's “Policy Statement Concerning Stand-Alone Assistance” is, for the most part, a summary of the powers of the Corporation under section 5.61(a) of the Act to provide assistance to a troubled System institution, including the timing and steps for making the least-cost test.
On June 21, 2012, the Corporation published for comment a draft “Policy Statement Concerning Assistance to Troubled Farm Credit System Institutions” to replace the Corporation's existing “Policy Statement Concerning Stand-Alone Assistance.”
In the first sentence of the draft policy statement, the Corporation stated that, in general, it would consider a request for assistance after other resolution alternatives have been exhausted such as voluntary assistance provided from within the System, voluntary merger with one or more System institutions, or involuntary merger with one or
In response to these comments, the Corporation is removing the language on “other resolution alternatives” that the commenters found troubling. To clarify, FCA action is not a necessary precondition for the Corporation to consider a request for assistance to a troubled System institution. The essential precondition for the Corporation to consider providing assistance is the receipt of a request for assistance and an assistance proposal. As explained in the final policy statement, a request for assistance can be initiated either directly from a troubled System institution or from other System institutions seeking to acquire or assist a troubled System institution. If the Corporation determines it is appropriate based on the facts and circumstances surrounding the request, the Corporation will provide System institutions the opportunity to submit information related to the request.
In the draft policy statement, the Corporation stated that it would conduct a least-cost test to determine whether the cost of providing assistance to a troubled System institution is less costly to the Insurance Fund than a liquidation of the institution. In brief, the Corporation would review the assistance proposal and gather any additional information necessary to estimate the cost of liquidation. Once this estimate has been computed, the Corporation would determine the cost and type of assistance. The Corporation would then compare the cost of providing assistance to the cost of liquidation to make its least-cost determination.
The draft policy statement also describes the complexity of conducting a least-cost test. For example, the Corporation describes a scenario where a sizable association is failing. The liquidation of the large association might not have an immediate impact on the funding bank's ability to continue meeting its insured obligations, but the effect of the liquidation could create significant disruption through a district that could threaten the bank's ability to continue as a going concern. Without assistance from the Corporation, the bank might eventually fail, creating greater losses to the Insurance Fund.
The Corporation received two comments on the least-cost test discussion. Both commenters generally agree with the principles behind the least-cost determination, specifically the discussion of considering the full impact on the Insurance Fund over time. However, the commenters also reference a separate document titled a “Least-Cost Test Example” that the Corporation shared publicly as an example of how the least-cost test might be performed if the troubled System institution was an association. In general, the commenters believed the assumptions used in this example were too optimistic.
In response to these comments, it appears the commenters misunderstood the purpose of the Least-Cost Test Example. The Corporation created this example as part of its fact-gathering process in the development phase of the draft policy statement; the example itself is not a part of the draft policy statement.
In view of the comments received, the Corporation is substantially revising the least-cost test discussion of the final “Policy Statement Concerning Assistance” to provide greater clarity concerning the “cost of liquidation” as it relates to the Insurance Fund. Since the Insurance Fund's primary purpose is to insure the timely payment of principal and interest on System bank insured debt obligations, it is clear that a loss to the Insurance Fund occurs when a System bank defaults on an insured debt obligation, and the Corporation must use the Insurance Fund to pay the obligation. In making the least-cost determination, the Corporation must be able to reasonably estimate whether the troubled System institution's failure will impair a bank's ability to pay its insured debt obligations, creating losses to the Insurance Fund. The final policy statement provides guidance for how the Corporation might reasonably estimate costs to either resolve a troubled System institution or stem financial contagion within the System.
After considering all comments received, the Corporation has given final approval to the “Policy Statement Concerning Assistance,” with changes. The existing “Policy Statement Concerning Stand-Alone Assistance” is withdrawn. The text of the final “Policy
The Farm Credit System Insurance Corporation (Corporation), in its sole discretion, is authorized under section 5.61(a) of the Farm Credit Act of 1971, as amended (Act), 12 U.S.C. 2277a–10(a), to provide, on such terms and conditions as the Corporation's Board of Directors may prescribe: (1) Stand-alone assistance in the form of loans, asset or debt security purchases, assumption of liabilities, or contributions: (a) To prevent the placing of the institution
If the Corporation receives a request for assistance, it must compare the cost of liquidation to the cost of providing assistance to determine the least costly alternative to the Insurance Fund.
The Corporation will consider a request for assistance to a troubled System institution under section 5.61(a) of the Act, 12 U.S.C. 2277a–10(a), upon receipt of an assistance proposal. An assistance proposal can be submitted either directly from a troubled System institution, from other System institutions seeking to acquire or assist a troubled System institution, or from the System banks to stem a liquidity crisis. Upon receipt of an assistance proposal, if the Corporation determines it is appropriate based on the facts and circumstances surrounding the request, the Corporation will provide System institutions the opportunity to submit any information, including information on the cost to the Farm Credit Insurance Fund (Insurance Fund) of a liquidation.
A System institution requesting assistance must submit a proposal to the Corporation. If the proposal is for stand-alone assistance, the proposal must provide justification for the assistance, including a detailed analysis of how such assistance will return the troubled System institution to a financially viable, self-sustaining operation. If the proposed assistance is to facilitate a merger, the proposal must demonstrate that the continuing System institution can safely and soundly absorb the financial and operational impact that will result from the merger. Moreover, the Corporation would consider FCA's preliminary approval of the proposed merger, pending the least-cost determination to provide assistance. If a System institution or group of System institutions submits an assistance proposal to resolve a troubled System institution or stem a liquidity crisis or financial contagion within the System, the proposal must contain sufficient information to demonstrate how the Corporation's assistance would be less costly to the Insurance Fund than liquidating the troubled System institution(s).
Assistance proposals must contain information to help the Corporation compare the cost of providing assistance to the cost of liquidating the troubled System institution as part of its least-cost determination. Assistance proposals can include requests for loans, loan guarantees, loss-sharing arrangements, asset or debt security purchases, assumption of liabilities, or cash contributions. The Corporation will consider the nature of the financial assistance requested on a case-by-case basis and may alter the form or amount of assistance as part of its determination. The Corporation has identified the following minimum criteria to be included in a request for assistance and assistance proposals:
(1) Financial condition and performance criteria to better understand the problem that caused the need for assistance, including the rationale for seeking assistance;
(2) The type and amount of assistance needed, as well as a reasonable repayment plan. Assistance proposals must include fee arrangements with attorneys, accountants, consultants, and other parties incident to the request for assistance (or projected costs for these arrangements). The Corporation would not acquire or service assets without a strong justification;
(3) Reasonable projections to assess the future viability of the institution after assistance has been provided. This
(4) A business plan that would implement written policies and procedures designed to guide operations safely and soundly and to correct the problems that caused the need for assistance. The plan must include an internal control system to monitor ongoing performance with measurable criteria. The plan must also include an operating budget, including compensation arrangements covering directors and senior officers. Plans to continue the service and compensation of directors and senior officers must be pre-approved by the Corporation before it provides assistance and until assistance is repaid; and
(5) Analysis of the effect of assistance on shareholders, uninsured creditors (e.g., impairment on subordinated debt), other System institutions and the financial markets. If the troubled System institution is an association, the analysis must include the impact on its funding bank's ability to continue meeting its insured obligations.
The Corporation reserves the right to request additional information as needed to conduct the least-cost test.
The Corporation will conduct a least-cost test to determine whether providing assistance to a troubled System institution is less costly to the Insurance Fund than liquidating the institution. The first step of the least-cost test is to determine the estimated liquidation value of the troubled System institution.
The second step of the least-cost test is for the Corporation to reasonably estimate whether the liquidation of the troubled System institution(s) creates a loss to the Insurance Fund. Since the Insurance Fund has been primarily established to insure the timely payment of principal and interest on System bank insured debt obligations,
A loss to the Insurance Fund may result from direct and/or indirect losses. Direct losses include the estimated losses to the Insurance Fund from the liquidation of a troubled System institution. Indirect losses to the Insurance Fund include the consequent effects of liquidating a troubled System institution. For example, if the troubled System institution is a bank, there is a direct loss to the Insurance Fund if the Corporation reasonably estimates that the net present value of the bank's assets
If the troubled System institution is an association, the Corporation must be able to reasonably estimate that the troubled System association's failure causes a loss to the Insurance Fund for there to be a basis for providing assistance. The funding bank would need to provide the Corporation with information to support the association request for assistance. If the Corporation reasonably estimates that the net present value of the association's assets
Moreover, if a sizable System association fails, or several smaller System associations fail, it is also possible that indirect losses to the Insurance Fund may result from association liquidations. For example, the liquidation of a considerable amount of agricultural loans in a relatively short period of time may cause a general decline in loan and collateral values throughout the district, creating higher
The third step of the least-cost test is to determine the type and amount of assistance. The cost of providing assistance will depend upon the structure of the assistance. For example, the Corporation's purchase of distressed assets from a troubled System institution may cost the Insurance Fund more than providing the institution a loan with a repayment plan.
The final step in the least-cost test is to compare the cost of liquidation to the cost of providing assistance. If the cost of providing assistance from the Insurance Fund is less than the cost of liquidating a troubled System institution (to the Insurance Fund), the Corporation's Board of Directors, in its discretion, may approve assistance to the troubled System institution. As required by statute, the Corporation shall use the information it receives during its least-cost determination to evaluate the alternatives, document the evaluation and the assumptions on which the evaluation is based, and retain the documentation for not less than 5 years.
If the Corporation provides assistance, it will enter into an agreement with the System institution receiving assistance. The terms and conditions of the agreement will be determined on a case-by-case basis and may include limits on (or prior approval of) the types or amounts of activities the institution can engage in while assistance is outstanding. For example, assistance agreements might include repayment terms and limits on concentration risk, patronage and dividend payments, executive compensation, and certain types of expenses. Assistance agreements may also provide the Corporation the right to have a representative attend the institution's board meetings. Each assistance agreement will be subject to the Corporation's Board of Directors' approval. While assistance agreements are outstanding, the Corporation will use its examination authority to ensure compliance with the agreement. Moreover, the Corporation will require the System institution receiving assistance to certify and publicly disclose compliance with the agreement requirements, including the disclosure of any instances of material noncompliance with the agreement.
Federal Election Commission.
Tuesday, April 23, 2013 at 10:00 a.m.
999 E Street NW., Washington, DC.
This meeting will be closed to the public.
Judith Ingram, Press Officer. Telephone: (202) 694–1220.
The Commission hereby gives notice of the filing of the following agreements under the Shipping Act of 1984. Interested parties may submit comments on the agreements to the Secretary, Federal Maritime Commission, Washington, DC 20573, within ten days of the date this notice appears in the
By Order of the Federal Maritime Commission.
The Commission gives notice that the following Ocean Transportation Intermediary licenses have been revoked pursuant to section 19 of the Shipping Act of 1984 (46 U.S.C. 40101) effective on the date shown.
The Commission gives notice that the following applicants have filed an application for an Ocean Transportation Intermediary (OTI) license as a Non-Vessel-Operating Common Carrier (NVO) and/or Ocean Freight Forwarder (OFF) pursuant to section 19 of the Shipping Act of 1984 (46 U.S.C. 40101). Notice is also given of the filing of applications to amend an existing OTI license or the Qualifying Individual (QI) for a licensee.
Interested persons may contact the Office of Ocean Transportation Intermediaries, Federal Maritime Commission, Washington, DC 20573, by telephone at (202) 523–5843 or by email at
By the Commission.
The Commission gives notice that it has rescinded its Order revoking the following licenses pursuant to section 19 of the Shipping Act of 1984 (46 U.S.C. 40101).
Board of Governors of the Federal Reserve System.
On June 15, 1984, the Office of Management and Budget (OMB) delegated to the Board of Governors of the Federal Reserve System (Board) its approval authority under the Paperwork Reduction Act (PRA), pursuant to 5 CFR 1320.16, to approve of and assign OMB control numbers to collection of information requests and requirements conducted or sponsored by the Board under conditions set forth in 5 CFR part 1320 Appendix A.1. Board-approved collections of information are incorporated into the official OMB inventory of currently approved collections of information. Copies of the Paperwork Reduction Act Submission, supporting statements and approved collection of information instruments are placed into OMB's public docket files. The Federal Reserve may not conduct or sponsor, and the respondent is not required to respond to, an information collection that has been extended, revised, or implemented on or after October 1, 1995, unless it displays a currently valid OMB control number.
Comments must be submitted on or before June 17, 2013.
You may submit comments, identified by
•
•
•
•
•
All public comments are available from the Board's Web site at
Additionally, commenters may send a copy of their comments to the OMB Desk Officer — Shagufta Ahmed — Office of Information and Regulatory Affairs, Office of Management and Budget, New Executive Office Building, Room 10235 725 17th Street NW., Washington, DC 20503 or by fax to (202) 395–6974.
A copy of the PRA OMB submission, including the proposed reporting form and instructions, supporting statement, and other documentation will be placed into OMB's public docket files, once approved. These documents will also be made available on the Federal Reserve Board's public Web site at:
Federal Reserve Board Clearance Officer — Cynthia Ayouch — Division of Research and Statistics, Board of Governors of the Federal Reserve System, Washington, DC 20551 (202) 452–3829. Telecommunications Device for the Deaf (TDD) users may contact (202) 263–4869, Board of Governors of the Federal Reserve System, Washington, DC 20551.
The following information collections, which are being handled under this delegated authority, have received initial Board approval and are hereby published for comment. At the end of the comment period, the proposed information collections, along with an analysis of comments and recommendations received, will be submitted to the Board for final approval under OMB delegated authority. Comments are invited on the following:
a. Whether the proposed collection of information is necessary for the proper performance of the Federal Reserve's functions; including whether the information has practical utility;
b. The accuracy of the Federal Reserve's estimate of the burden of the proposed information collection, including the validity of the methodology and assumptions used;
c. Ways to enhance the quality, utility, and clarity of the information to be collected;
d. Ways to minimize the burden of information collection on respondents, including through the use of automated
e. Estimates of capital or start up costs and costs of operation, maintenance, and purchase of services to provide information.
Proposal to approve under OMB delegated authority the extension for three years, with revision, of the following report:
Electronic Government Office, HHS.
Notice.
In compliance with section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the Electronic Government Office (EGOV), Department of Health and Human Services, has submitted an Information Collection Request (ICR), described below, to the Office of Management and Budget (OMB) for review and approval. The ICR is for reinstatement of a previously-approved information collection assigned OMB control number 4040–0001, which expired on March 31, 2013. The ICR also requests categorizing the form as a common form, meaning HHS will only request approval for its own use of the form rather than aggregating the burden estimate across all Federal Agencies as was done for previous actions on this OMB control number. Comments submitted during the first public review of this ICR will be provided to OMB. OMB will accept further comments from the public on this ICR during the review and approval period.
Comments on the ICR must be received on or before May 20, 2013.
Submit your comments to
Information Collection Clearance staff,
When submitting comments or requesting information, please include the OMB control number 4040–0001 and document identifier HHS–EGOV–18380–30D for reference.
HHS estimates that the SF–424 Research and Related form will take 1 hour to complete.
We expect that 128,378 respondents will use this form.
Once OMB approves the use of this common form, federal agencies may request OMB approval to use this common form without having to publish notices and request public comments for 60 and 30 days. Each agency must account for the burden associated with their use of the common form.
Office of the Secretary, HHS.
Notice.
Notice is hereby given that effective on March 14, 2013, a Settlement Agreement was made and entered into by and between Dr. Philippe Bois and the United States Department of Health and Human Services (HHS), Kathleen Sebelius, Howard K. Koh, Nancy Gunderson, and Donald Wright (collectively HHS) by and through the United States Attorney for the District of Columbia in
In the Settlement Agreement, HHS and Dr. Bois agreed to settle the proceedings before the District Court of the District of Columbia as well as to resolve all administrative matters pending at HHS.
ORI found that Philippe Bois, Ph.D., former postdoctoral fellow, Department of Biochemistry, St. Jude Children's Research Hospital, engaged in research misconduct in research funded by National Institute of General Medical Sciences (NIGMS), National Institutes of Health (NIH), grant R01 GM071596, and National Cancer Institute (NCI), NIH, grants P30 CA021765, P01 CA071907, R01 CA072996, and R01 CA100603.
In the Settlement Agreement, the parties agreed that ORI found by a preponderance of the evidence that the Respondent committed misconduct in science and research misconduct by:
1. Knowingly and intentionally falsely reporting that FOXO1a was not expressed in cell lysates from alveolar rhabdomyosarcoma (ARMS) tumor biopsies, by selecting a specific FOX01a immunoblot to show the desired result, in Figure 1A of the following paper: Bois, P.R., Izeradjene, K., Houghton, P.J., Cleveland, J.L., Houghton, J.A., & Grosveld, C.G. “FOXO1a acts as a selective tumor suppressor in alveolar rhabdomyosarcoma.”
2. Falsifying data showing SDS–PAGE for papain digestion of VBS3 and αVBS, by falsely labeling lane 1 to represent papain only digestion, by falsely labeling lane 5 to represent papain digestion of the αVBS peptide, and by falsely inserting a band in lane 3 to represent the αVBS peptide, in Figure 4B of the following paper: Bois, P.R., Borgon, R.A., Vornhein, C., & Izard, T. “Structural dynamics of α-actinin-vinculin interactions.”
The parties further agreed that Dr. Bois denied committing research misconduct and, pursuant to 42 CFR part 93, filed a timely request for a hearing at which to contest ORI's findings. An HHS Administrative Law Judge (ALJ) denied Dr. Bois' request for a hearing. HHS subsequently entered a debarment order against Dr. Bois. Dr. Bois filed the above referenced lawsuit in the United States District Court for the District of Columbia asking the Court to vacate the debarment order and remand the matter for further proceedings before HHS, including but not limited to granting Dr. Bois' request for a hearing.
On March 2, 2012, Judge Berman Jackson of the United States District Court for the District of Columbia issued an order vacating HHS' debarment order, affirming Finding #1, and remanding the matter to HHS for further proceedings regarding Finding #2. On March 30, 2012, HHS filed a Motion for Reconsideration before Judge Berman Jackson.
On March 14, 2013, Dr. Bois and HHS entered into a Settlement Agreement (Agreement) to settle and dismiss the pending civil action. The terms of the
(1) To have his research supervised for a period of three (3) years beginning on the effective date of the Agreement; he agreed that prior to the submission of an application for U.S. Public Health Service (PHS) support for a research project on which his participation is proposed and prior to his participation in any capacity on PHS-supported research, he shall ensure that a plan for supervision of his duties is submitted to ORI for approval; the supervision plan must be designed to ensure the scientific integrity of his research contribution; he agreed that he shall not participate in any PHS-supported research until such a supervision plan is submitted to and approved by ORI, with such review and approval to be conducted promptly by ORI and not unreasonably withheld; he agreed to maintain responsibility for compliance with the agreed upon supervision plan;
(2) that for three (3) years beginning with the effective date of the Agreement, any institution employing him shall submit, in conjunction with each application for PHS funds, or report, manuscript, or abstract involving PHS-supported research in which Dr. Bois is involved, a certification to ORI that the data provided by him are based on actual experiments or are otherwise legitimately derived and that the data, procedures, and methodology are accurately reported in the application, report, manuscript, or abstract; and
(3) to exclude himself voluntarily from serving in any advisory capacity to PHS, including, but not limited to, service on any PHS advisory committee, board, and/or peer review committee, or as a consultant for a period of three years (3) beginning with the effective date of the Agreement.
Dr. Bois further agreed to dismiss his lawsuit with prejudice and to withdraw further proceedings before HHS. Dr. Bois and HHS both agreed to waive or abandon all other claims. This notice supercedes the notice regarding this matter that was previously published in:
Director, Division of Investigative Oversight, Office of Research Integrity, 1101 Wootton Parkway, Suite 750, Rockville, MD 20852, (240) 453–8800.
Agency for Healthcare Research and Quality, HHS.
Notice.
This notice announces the intention of the Agency for Healthcare Research and Quality (AHRQ) to request that the Office of Management and Budget (OMB) approve the proposed information collection project: “Pilot Test of the Proposed Value and Efficiency Surveys and Communicating with Patients Checklist.” In accordance with the Paperwork Reduction Act, 44 U.S.C. 3501–3521, AHRQ invites the public to comment on this proposed information collection.
This proposed information collection was previously published in the
Comments on this notice must be received by May 20, 2013.
Written comments should be submitted to: AHRQ's OMB Desk Officer by fax at (202) 395–6974 (attention: AHRQ's desk officer) or by email at
Copies of the proposed collection plans, data collection instruments, and specific details on the estimated burden can be obtained from the AHRQ Reports Clearance Officer.
Doris Lefkowitz, AHRQ Reports Clearance Officer, (301) 427–1477, or by email at
Maximizing value within the American health care system is an important priority. Value is often viewed as a combination of high quality, high efficiency care, and there is general agreement by consumers, policy makers, payers, and providers that it is lacking in the U.S. A recent report by the Institute of Medicine estimated that 20 to 30 percent ($765 billion a year) of U.S. healthcare spending was inefficient and could be reduced without lowering quality.
Multiple overlapping initiatives are currently seeking to improve value using a variety of approaches. Public reporting efforts led by the Centers for Medicare and Medicaid Services (CMS), other payers and consumer groups seek to enable consumers to make more informed choices about the quality, and in some cases, the costs of their care. A variety of demonstration projects and payment reforms initiated by CMS and private insurers are attempting to more closely link care quality with payments to create incentives for higher value care. And national improvement initiatives led by AHRQ (comprehensive unit-based safety programs [CUSP] for central line-associated blood stream infection [CLABSI], catheter-associated urinary tract infections [CUTI], and surgical units [SUSP]) and CMS (hospital engagement networks, QIO scopes of work) are seeking to raise care quality and reduce readmissions. Results from the CUSP–CLABSI project have demonstrated that central line infections can be reduced and unnecessary costs can be avoided across the health care system by concerted, unit-based improvement efforts.
As a systems level example, Denver Health, with initial funding from AHRQ, has taken major steps towards redesigning clinical and administrative processes so as to reduce staff time, patient waiting, and unnecessary costs. These improvements occurred without harm to quality and in some instances actually improved quality.
In many cases, improving quality improves efficiency naturally. Reducing the number of hospital errors, for example, will reduce costs associated with longer length of stay or error-triggered readmissions. It is more cost-effective to do things right the first time. But higher value may be more likely if organizations doing quality improvement link efforts to improve care quality with efforts to reduce unnecessary costs. AHRQ understands that many of the root causes of inefficiencies that drive up costs are closely linked to root causes of inefficiencies that lead to poor quality, uncoordinated care where redundancies and system failures place patients at risk. Enhancing value in healthcare
If organizations lack cultures committed to value then discrete efforts to raise dimensions of value are likely to yield limited and unsustainable results. And if organizational leaders have no plausible way to know whether their organizational culture is committed to value, then their ability to make value a higher organizational priority will be very limited. Thus, developing value and efficiency survey instruments for hospitals and medical offices fills an important need for many ongoing and planned efforts to foster greater value within American health care.
Given the widespread impact of cost and waste in health care, AHRQ will develop the Value and Efficiency (VE) Surveys for hospitals and medical offices. These surveys will measure staff perceptions about what is important in their organization and what attitudes and behaviors related to value and efficiency are supported, rewarded, and expected. The surveys will help hospitals and medical offices to identify and discuss strengths and weaknesses within their individual organizations. They can then use that knowledge to develop appropriate action plans to improve their value and efficiency. To develop these tools AHRQ will recruit medical staff from 42 hospitals and 96 medical offices to participate in cognitive testing and pretesting.
In addition to the VE surveys, AHRQ also intends to develop and test the feasibility and utility of a Patient Communication Checklist. Patients are demanding greater clarity into the costs of health care and what they can do about affordability problems. While there is recent interest in making health care prices more transparent for consumers (e.g., the Health Care Price Transparency Promotion Act of 2013 (H.R. 1326)), physician communication with patients about the cost of care will be a key component to attaining high-value, high-quality care from a patient perspective. To aid physicians, this proposal will develop a consumer value (CV) checklist. Physician checklists have been instrumental in many quality improvements, such as with AHRQ's reduction in central line-associated blood stream infections [CLABSI] (See Atul Gawande's Checklist Manifesto, Metropolitan Books, 2009). Checklists have also reduced surgical complications by preventing miscommunication during complex procedures. Similarly, checklists could potentially facilitate communication between clinicians and patients in complex discussions about patient preferences, quality, value, and out-of-pocket costs. The objective of the CV checklist is to facilitate shared decision-making, and also engage physician and patients in joint problem solving. For example, if discussions emanating from use of a checklist show that the patient is not likely to fill a critical prescription for financial reasons, this could trigger a discussion of generic substitutes or state or other subsidies available. Since the proper goal for any health care delivery system is to improve the quality and value of care delivered to patients, such a tool will bring the patient perspective on value into the decision-making about their care.
The CV checklist will address three major topics: who should talk with patients about preferences and value issues (e.g., nurses, physicians, etc.), when should these conversations occur (e.g., when patients may incur costs, when they express financial concerns, etc.), and how can clinicians prepare for and effectively facilitate such discussions.
This research has the following goals:
(1) Develop, cognitively test and modify as necessary the VE surveys (one for hospitals and one for medical offices);
(2) Pretest the VE surveys in hospitals and medical offices and modify as necessary based on the results;
(3) Develop, cognitively test and modify as necessary the checklist;
(4) Seek consumer/patient input on the potential value of the checklist;
(5) Pretest the checklist in hospitals and medical offices and either drop or modify as necessary based on patient and clinician views of the results;
(6) Make the final VE surveys and checklist available for use by the public.
This study is being conducted by AHRQ through its contractor, Health Research & Educational Trust (HRET), and subcontractor, Westat, pursuant to AHRQ's statutory authority to conduct and support research on healthcare and on systems for the delivery of such care, including activities with respect to the quality, effectiveness, efficiency, appropriateness and value of healthcare services and with respect to quality measurement and improvement. 42 U.S.C. 299a(a)(1) and (2).
To achieve these goals the following activities and data collections will be implemented:
(1) Cognitive interviews for the YE surveys. One round of interviews on the VE surveys will be conducted by telephone with 9 respondents from hospitals and 9 respondents from medical offices. The purpose of these interviews is to understand the cognitive processes the respondent engages in when answering a question on the VE survey and to refine the survey's items and composites. These interviews will be conducted with a mix of senior leaders and clinical staff (i.e., unit/department managers, practitioners, nurses, technicians, and medical assistants) from hospitals and medical offices throughout the U.S. with varying characteristics (e.g., size, geographic location, type of medical office practice/hospital, and possibly extent of experience with waste-reduction efforts).
(2) Pretest for the VE surveys. The surveys will be pretested with senior leaders and clinical staff from 42 hospitals and 96 medical offices. The purpose of the pretest is to collect data for an assessment of the reliability and construct validity of the surveys' items and composites, allowing for their further refinement. A site-level point-of-contact (POC) will be recruited in each medical office and hospital to manage the data collection at that organization (compiles sample information, distribute surveys, promote survey response, etc.). Exhibit 1 includes a burden estimate for the POC's time to manage the data collection.
(3) Medical office information form. This form will be completed by the medical office manager in each of the 96 medical office pretest sites to provide background characteristics, such as type of specialty(s) and majority ownership. A hospital information form will not be needed because characteristics on pretest hospitals will be obtained from the American Hospital Association's (AHA) data set based on a hospital's AHA ID number.
(4) Survey to identify items for CV checklist. In order to identify items to
(5) Cognitive Interviews for the CV checklist. Once checklist items have been identified, cognitive interviews will be conducted with 9 respondents in hospitals and 9 respondents in medical offices to understand the cognitive processes the respondent engages in when using the CV checklist. Cognitive interviewing will allow checklist developers to identify and classify difficulties respondents may have regarding checklist items. To get different perspectives, interviews will be conducted with a mix of physicians, nurses, social workers, health educators, and patients in hospitals and medical offices.
(6) Pretest the CV checklist. The checklist will then be pretested to solicit feedback from 50 physicians in hospitals and 50 physicians in medical offices. The pilot testing process will help identify areas where users of the checklist have trouble understanding, learning, and using the checklist. It also provides the opportunity to identify issues that can prevent successful deployment of the checklist.
(7) Dissemination activities. The final VE Surveys and CV checklist will be made available to the public through the AHRQ Web site. This activity does not impose a burden on the public and is therefore not included in the burden estimates in Exhibit 1.
The information collected will be used to test and improve the draft survey items in the VE Surveys and CV checklist.
The final VE instruments will be made available to the public for use in hospitals and medical offices to assess value and efficiency from the perspectives of their staff. The survey can be used by hospitals and medical offices to identify areas for improvement. Researchers are also likely to use the surveys to assess the impact of hospitals' and medical offices' value and efficiency improvement initiatives.
The final CV checklist will be made available to hospital and medical office clinicians to aid in having conversations with patients about value.
Exhibit 1 shows the estimated annualized burden hours for the respondents' time to participate in this research. Cognitive interviews for the Hospital VE survey will be conducted with 9 hospital staff (approximately 3 managers, 3 nurses, and 3 technicians) and will take about one hour and 30 minutes to complete. Cognitive interviews for the Medical Office VE survey will be conducted with 9 medical office staff (approximately 4 physicians and 5 medical assistants) and will take about one hour and 30 minutes to complete. The Hospital VE survey will be administered to about 4,032 individuals from 42 hospitals (about 96 surveys per hospital) and requires 15 minutes to complete. A site-level POC will spend approximately 16 hours administering the Hospital VE survey. The Medical Office VE survey will be administered to about 504 individuals from 96 medical offices (about 5 surveys per medical office) and requires 15 minutes to complete. A site-level POC will spend approximately 6 hours administering the Medical Office VE survey. The medical office information form survey will be completed by a medical office manager at each of the 96 medical offices participating in the pretest and takes 10 minutes to complete.
One-hundred and sixty individuals (40 physicians, 40 nurses, 20 social workers, 20 health educators, and 40 patients) will participate in the survey to identify items for the CV checklist and will take 15 minutes to complete. Cognitive interviews for the CV checklist will be conducted with 18 individuals (9 in hospitals and 9 in medical offices, consisting of approximately 4 physicians, 4 nurses, 2 social workers, 2 health educators, and 6 patients) and will take about one hour to complete. One hundred physicians will participate in the pretest of the CV checklist (50 in hospitals and 50 in medical offices). The total burden is estimated to be 2,534 hours annually.
Exhibit 2 shows the estimated annualized cost burden associated with the respondents' time to participate in this research. The total cost burden is estimated to be $115,559 annually.
Exhibit 3 shows the estimated total and annualized cost to the government for this data collection. Although data collection will last for less than one year, the entire project will take about 2 years. The total cost for the three surveys is approximately is $1,001,202.
In accordance with the Paperwork Reduction Act, comments on AHRQ's information collection are requested with regard to any of the following: (a) Whether the proposed collection of information is necessary for the proper performance of AHRQ health care research and health care information dissemination functions, including whether the information will have practical utility; (b) the accuracy of AHRQ's estimate of burden (including hours and costs) of the proposed collection(s) of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information upon the respondents, including the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and included in the Agency's subsequent request for OMB approval of the proposed information collection. All comments will become a matter of public record.
Agency for Healthcare Research and Quality (AHRQ), HHS.
Notice of request for measures and domains.
Section 401(a) of the Children's Health Insurance Program Reauthorization Act of 2009 (CHIPRA), Public Law 111–3, amended the Social Security Act (the Act) to enact section 1139A (42 U.S.C. 1320b–9a). Section 1139A(b) charged the Department of Health and Human Services with improving pediatric health care quality measures. The Agency for Healthcare Research and Quality (AHRQ) is requesting the submission of instruments or domains (for example, key concepts) measuring aspects of the transition from child-focused to adult-focused care in young adults with chronic health conditions from all researchers, vendors, hospitals, stakeholders, and other interested parties. AHRQ is interested in instruments and items through which young adults or parent proxies may assess experiences they have with the health care system, including the transition from pediatric to adult health care. The goal is to develop a standardized instrument for use in assessing the quality of transition from child-focused to adult-focused care in young adults with chronic health conditions.
Please submit materials May 20, 2013. AHRQ will not respond to individual submissions, but will consider all suggestions.
Electronic submissions are encouraged, preferably as an email with an electronic file in a standard word processing format as an email attachment. Submissions may also be in the form of a letter to: Maushami DeSoto, M.Sc., Ph.D., MHA. Office of Extramural Research, Education and Priority Populations, Agency for Healthcare Research and Quality, 540 Gaither Rd., Rockville, MD 20850, Phone: (301) 427–1546, Fax: (301) 427–1238, Email:
All submissions must include a written statement from the submitter that it will grant AHRQ the necessary rights to use, modify, and adapt the submitted instruments, domains, items, and their documentation for the development of this survey and its dissemination for AHRQ purposes. The statement must also address the instrument's proprietary and/or confidentiality status. In accordance with CHIPRA's charge to improve pediatric quality care measures, and consistent with AHRQ's mandate to disseminate research results, 42 U.S.C. 299c–3, AHRQ purposes include public disclosure and dissemination (e.g., on the AHRQ Web site) of AHRQ products and the results of AHRQ-sponsored research and activities. The written statement must be signed by the copyright holder or an individual authorized to act for any holder of copyright and/or data rights on each submitted measure or instrument. The authority of the signatory to provide such authorization should be described in the letter. If the submitted measure or instrument is selected for further development AHRQ will request that the submitter execute a license granting all of the above-referenced rights to the Department of Health and Human Services.
When submitting instruments, please include, to the extent that it is available:
When submitting domains, please include, to the extent available:
For all submissions, please also include:
A brief cover letter summarizing the information requested above for submitted instruments and domains, respectively;
Complete information about the person submitting the material, including:
(a) Name;
(b) Title;
(c) Organization;
(d) Mailing address;
(e) Telephone number;
(f) Email address; and,
(g) A written statement of intent that the submitter will grant to AHRQ the necessary rights to use, modify, and adapt the submitted instruments, items, and their supporting documentation for the development of the survey and its dissemination for AHRQ purposes, as described above.
Maushami DeSoto, M.Sc., Ph.D., MHA.
Section 401(a) of the Children's Health Insurance Program Reauthorization Act of 2009 (CHIPRA), Public Law 111–3, amended the Social Security Act (the Act) to enact section 1139A (42 U.S.C. 1320b-9a). Since the law was passed, the Agency for Healthcare Research and Quality (AHRQ) and the Centers for Medicare & Medicaid Services (CMS) have been working together to implement selected provisions of the legislation related to children's health care quality. Section 1139A(b) of the Act charged the Department of Health and Human Services with improving pediatric health care quality measures. To implement the law, AHRQ and CMS have established the CHIPRA Pediatric Quality Measures Program (PQMP), which is designed to enhance select pediatric quality measures and develop new measures as needed.
The information sought in this Notice is being collected pursuant to the needs of the Children's Hospital Boston Center of Excellence for Pediatric Quality Measurement (CEPQM). It is one of the seven CHIPRA Pediatric Quality Measures Program (PQMP) Centers of Excellence and has been assigned the task of developing measures to assess aspects of the transition from child-focused to adult-focused care in young adults with chronic health conditions. To thoroughly carry out this task, the Center needs to identify and assess instruments or domains which already exist on this subject. Such measures will be considered in the development of a standardized instrument for voluntary public reporting by State Medicaid and CHIP programs and used by providers, consumers, other public and private purchasers, and others.
Existing instruments or domains submitted should capture adolescents' experiences with their health care, including the transition from pediatric
Agency for Healthcare Research and Quality (AHRQ), HHS.
Solicits nominations for new members of USPSTF.
The Agency for Healthcare Research and Quality (AHRQ) invites nominations of individuals qualified to serve as members of the U.S. Preventive Services Task Force (USPSTF).
All nominations submitted in writing or electronically will be considered for appointment to the USPSTF. Nominations must be received by May 15th of a given year to be considered for appointment to begin in January of the following year.
Nominations and applications are kept on file at the Center for Primary Care, Prevention, and Clinical Partnerships, AHRQ, and are available for review during business hours. AHRQ does not reply to individual nominations, but considers all nominations in selecting members. Information regarded as private and personal, such as a nominee's social security number, home and email addresses, home telephone and fax numbers, or names of family members will not be disclosed to the public (in accord with the Freedom of Information Act, 5 U.S.C. 552(b)(6); 45 CFR 5.67).
Submit your responses either in writing or electronically to:
Nominations may be submitted in writing or electronically, but must include:
(1) The applicant's current curriculum vitae and contact information, including mailing address, email address, and telephone number, and
(2) a letter explaining how this individual meets the qualification requirements and how he/she would contribute to the USPSTF. The letter should also attest to the nominee's willingness to serve as a member of the USPSTF.
AHRQ will later ask persons under serious consideration for USPSTF membership to provide detailed information that will permit evaluation of possible significant conflicts of interest. Such information will concern matters such as financial holdings, consultancies, and research grants or contracts.
Appointments to the USPSTF will be made on the basis of qualifications as outlined below (see Qualification Requirements) and the current expertise needs of the USPSTF.
Robert Cosby at
Under Title IX of the Public Health Service Act, AHRQ is charged with enhancing the quality, appropriateness, and effectiveness of health care services and access to such services. 42 U.S.C. 299(b). AHRQ accomplishes these goals through scientific research and promotion of improvements in clinical practice, including clinical prevention of diseases and other health conditions, and improvements in the organization, financing, and delivery of health care services. See 42 U.S.C. 299(b).
The USPSTF, an independent body of experts in prevention and evidence-based medicine, works to improve the health of all Americans by making evidence-based recommendations about the effectiveness of clinical preventive services and health promotion. The recommendations made by the USPSTF address clinical preventive services for adults and children, and include screening tests, counseling services, and preventive medications.
The USPSTF was first established in 1984 under the auspices of the U.S. Public Health Service. Currently, the USPSTF is convened by the Director of AHRQ, and AHRQ provides ongoing administrative, research and technical support for the USPSTF's operation. USPSTF members serve for four year terms. New members are selected each year to replace those members who are completing their appointments.
The USPSTF is charged with rigorously evaluating the effectiveness, cost-effectiveness and appropriateness of clinical preventive services and formulating or updating recommendations regarding the appropriate provision of preventive services. See 42 U.S.C. 299b–4(a)(1). AHRQ is charged with supporting the dissemination of USPSTF recommendations. In addition to hard copy materials (that may be obtained from the AHRQ Publications Clearinghouse), current USPSTF recommendations and associated evidence reviews are available on the Internet (
USPSTF members meet three times a year for two days in the Washington, DC area. A significant portion of the USPSTF's work occurs between meetings during conference calls and via email discussions. Member duties include prioritizing topics, designing research plans, reviewing and commenting on systematic evidence reviews of evidence, discussing and making recommendations on preventive-services, reviewing stakeholder comments, drafting final recommendation documents, and participating in workgroups on specific topics and methods. Members can expect to receive frequent emails, can expect to participate in multiple conference calls each month, and can expect to have periodic interaction with stakeholders. AHRQ estimates that members devote approximately 200 hours a year outside of in-person meetings to their USPSTF duties. The members are all volunteers and do not receive any compensation beyond support for travel to in person meetings.
Nominated individuals will be selected for the USPSTF on the basis of their qualifications (in particular, those that address the required qualifications, outlined below) and the current expertise needs of the USPSTF. It is anticipated that three to four individuals will be invited to serve on the USPSTF beginning in January 2014. All individuals will be considered; however, strongest consideration will be
To obtain a diversity of perspectives, AHRQ particularly encourages nominations of women, members of minority populations, and persons with disabilities. Interested individuals can self nominate. Organizations and individuals may nominate one or more persons qualified for membership on the USPSTF at any time. Individuals nominated prior to May 15, 2012, who continue to have interest in serving on the USPSTF, should be re-nominated.
1. The critical evaluation of research published in peer reviewed literature and in the methods of evidence review;
2. Clinical prevention, health promotion and primary health care; and
3. Implementation of evidence-based recommendations in clinical practice including at the clinician-patient level, practice level, and health system level.
Some USPSTF members without primary health care clinical experience may be selected based on their expertise in methodological issues such as meta-analysis, analytic modeling or clinical epidemiology. For individuals with clinical expertise in primary health care, additional qualifications in methodology would enhance their candidacy.
Additionally, the Task Force benefits from members with expertise in the following areas:
• Public health
• Health equity and the reduction of health disparities
• Application of science to health policy
• Communication of scientific findings to multiple audiences including health care professionals, policy makers and the general public.
Candidates with experience and skills in any of these areas should highlight them in their nomination materials.
Applicants must have no substantial conflicts of interest, whether financial, professional, or intellectual, that would impair the scientific integrity of the work of the USPSTF and must be willing to complete regular conflict of interest disclosures.
Applicants must have the ability to work collaboratively with a team of diverse professionals who support the mission of the USPSTF. Applicants must have adequate time to contribute substantively to the work products of the USPSTF.
The purpose of this study is to improve understanding of how local Head Start and Early Head Start programs define, measure, and communicate school readiness goals, and how they use these goals in program planning to improve program functioning. The study design will include a telephone survey of program directors or designated key personnel at approximately 90 local Head Start and Early Head Start programs, followed by site visits to collect further qualitative information through interviews with program staff, oversight boards, key stakeholders and parents at a subset of 12 of these grantees. In addition, telephone interviews will be conducted with 4 Head Start directors of American Indian/Alaskan Native (AIAN) grantees.
Topics covered in the telephone survey, site visits, and qualitative interviews include: a description of school readiness goals set by local grantee; the process used to set school readiness goals; contextual factors informing choices made about school readiness goals (e.g., needs of local children and families, program and staff characteristics, and community characteristics); how programs use and analyze data about school readiness goals; how programs report progress on goals; and how school readiness goals and data inform program planning and improvement efforts.
Estimated Total Annual Burden Hours: 323.
Family and Youth Services Bureau (FYSB), Administration on Children, Youth, and Families (ACYF), ACF, HHS.
This notice was originally published as Funding Opportunity Number HHH2013–ACF–ACYF–SDVC–0564 on March 5, 2013 at
This announcement governs the proposed award of mandatory grants under the Family Violence Prevention and Services Act (FVPSA) to States (including territories and insular areas). The purpose of these grants is to: (1) assist States in efforts to increase public awareness about, and primary and secondary prevention of, family violence, domestic violence, and dating violence; and (2) assist States in efforts to provide immediate shelter and supportive services for victims of family violence, domestic violence, or dating violence (42 U.S.C. 10401 et seq.).
This announcement sets forth the application requirements, the application process, and other administrative and fiscal requirements for grants in Fiscal Year (FY) 2013, 2014 and 2015.
The statutory authority for this program is 42 U.S.C. 10401 through 10414 hereinafter cited by Section number only.
The Administration on Children, Youth and Families (ACYF) is committed to facilitating healing and recovery, and promoting the social and emotional well-being of victims, children, youth, and families who have experienced domestic violence, maltreatment, exposure to violence, and trauma. An important component of promoting well-being in this regard includes addressing the impact of trauma, which can have profound impacts on coping, resiliency, and skill development. ACYF promotes a trauma-informed approach, which involves understanding and responding to the symptoms of chronic interpersonal trauma and traumatic stress across the lifespan.
This FVPSA funding opportunity announcement (FOA), administered through ACYF's Family and Youth Services Bureau (FYSB), is designed to assist States in their efforts to support the establishment, maintenance, and expansion of programs and projects: (1) To prevent incidents of family violence, domestic violence, and dating violence; (2) to provide immediate shelter, supportive services, and access to community-based programs for victims of family violence, domestic violence, or dating violence, and their dependents; and (3) to provide specialized services for children exposed to family violence, domestic violence, or dating violence, underserved populations, and victims who are members of racial and ethnic minority populations (Section 10406(a)).
The FVPSA State Formula Grant funds shall be used to identify and provide subgrants to eligible entities for programs and projects within the State that are designed to prevent incidents of family violence, domestic violence, and dating violence by providing immediate shelter and supportive services for adult and youth victims of family violence, domestic violence, or dating violence, and their dependents, and which may be used to provide prevention services to prevent future incidents of family violence, domestic violence, and dating violence (Section 10408 (a)).
FVPSA funds awarded to subgrantees should be used for:
• Provision of immediate shelter and related supportive services to adult and youth victims of family violence, domestic violence, or dating violence, and their dependents, including paying for the operating and administrative expenses of the facilities for a shelter.(Section 10408(b)(1)(A)).
• Assistance in developing safety plans and supporting efforts of victims of family violence, domestic violence, or dating violence to make decisions related to their ongoing safety and well-being (Section 10408(b)(1)(B)).
• Provision of individual and group counseling, peer support groups, and referral to community-based services to assist family violence, domestic violence, and dating violence victims, and their dependents, in recovering from the effects of the violence (Section 10408(b)(1)(C)).
• Provision of services, training, technical assistance, and outreach to increase awareness of family violence, domestic violence, and dating violence, and increase the accessibility of family violence, domestic violence, and dating violence services (Section 10408(b)(1)(D)).
• Provision of culturally and linguistically appropriate services (Section 10408(b)(1)(E)).
• Provision of services for children exposed to family violence, domestic violence, or dating violence, including age-appropriate counseling, supportive services, and services for the nonabusing parent that support that parent's role as a caregiver, which may, as appropriate, include services that work with the nonabusing parent and child together (Section 10408(b)(1)(F)).
• Provision of advocacy, case management services, and information and referral services, concerning issues related to family violence, domestic violence, or dating violence intervention and prevention, including: (1) Assistance in accessing related Federal and State financial assistance programs; (2) legal advocacy to assist victims and their dependents; (3) medical advocacy, including provision of referrals for appropriate health care services (including mental health, alcohol, and drug abuse treatment), which does not include reimbursement for any health care services; (4) assistance locating and securing safe and affordable permanent housing and homelessness prevention services; (5) transportation, child care, respite care, job training and employment services, financial literacy services and education, financial planning, and related economic empowerment services; and (6) parenting and other educational services for victims and their dependents (Section 10408(b)(1)(G)).
• Provision of prevention services, including outreach to underserved populations (Section 10408(b)(1)(H)).
In the distribution of FVPSA grant funds, the State should ensure that not less than 70 percent of the funds distributed are used for the primary purpose of providing immediate shelter and supportive services to adult and youth victims of family violence, domestic violence, or dating violence, and their dependents; not less than 25 percent of the funds will be used for the purpose of providing supportive services and prevention services (Section 10408(b)(2)); and not more than 5 percent of the FVPSA grant funds should be used for State administrative costs (Section 10406(b)(1)).
ACYF is committed to facilitating healing and recovery, and promoting the social and emotional well-being of children, youth, and families who have experienced maltreatment, exposure to violence, and/or trauma. This FOA and other discretionary spending this fiscal year are designed to ensure that effective interventions are in place to build skills and capacities that contribute to the healthy, positive, and productive functioning of families.
Children, youth, and families who have experienced maltreatment, exposure to violence, and/or trauma are impacted along several domains, each of which must be addressed in order to foster social and emotional well-being and promote healthy, positive functioning:
•
•
•
The skills and capacities in these areas support children, youth, and families as challenges, risks, and opportunities arise. In particular, each domain impacts the capacity of children, youth, and families to establish and maintain positive relationships with caring adults and supportive peers. The necessity of these relationships to social and emotional well-being and lifelong success in school, community, and at home cannot be overstated and should be central to all interventions with vulnerable children, youth, and families.
An important component of promoting social and emotional well-being includes addressing the impact of trauma, which can have a profound effect on the overall functioning of children, youth, and families. ACYF promotes a trauma-informed approach, which involves understanding and responding to the symptoms of chronic interpersonal trauma and traumatic stress across the domains outlined above, as well as the behavioral and mental health sequelae of trauma.
ACYF anticipates a continued focus on social and emotional well-being as a critical component of its overall mission to ensure positive outcomes for all children, youth, and families.
FVPSA State Administrators shall plan to attend the annual grantee meeting. The State FVPSA Administrators meeting is a training and technical assistance activity focusing on FVPSA administrative issues as well as the promotion of evidence informed and promising practices to address family violence, domestic violence, or dating violence. Subsequent correspondence will advise the FVPSA State Administrators of the date, time, and location of their grantee meeting.
In order to ensure the safety of adult, youth, and child victims of family violence, domestic violence, or dating violence, and their families, FVPSA-funded programs must establish and implement policies and protocols for maintaining the confidentiality of records pertaining to any individual provided domestic violence services. Consequently, when providing statistical data on program activities and program services, individual identifiers of client records will not be used by the State or other FVPSA grantees or subgrantees (Section 10406(c)(5)).
In the annual grantee Performance Progress Report (PPR), States and subgrantees must collect unduplicated data from each program rather than unduplicated data across programs or statewide. No client-level data should be shared with a third party, regardless of encryption, hashing, or other data security measures, without a written, time-limited release as described in section 10406(c)(5). The address or location of any FVPSA-supported shelter facility shall not be made public except with written authorization of the person or persons responsible for the operation of such shelter, (See Section 10406(c)(5)(H)) and the confidentiality of records pertaining to any individual provided domestic violence services by any FVPSA-supported program will be strictly maintained.
It is essential that community service providers, including those serving or representing underserved communities, are involved in the design and improvement of intervention and prevention activities identified in the state plan. Coordination and collaboration among victim services providers; community-based, culturally specific, and faith-based services providers; housing and homeless services providers; and Federal, State, and local public officials and agencies is needed for an effective state planning process and to provide more responsive and effective services to victims of family violence, domestic violence, and dating violence, and their dependents. It is expected that the communities and organizations noted above will be included in committees or other activities to ensure they are part of the planning and decision making to create and maintain fully coordinated and accessible services.
To promote a more effective response to family violence, domestic violence, and dating violence, States receiving funds under this grant announcement must collaborate with State Domestic Violence Coalitions and community-based organizations and should collaborate with tribes, tribal organizations, and service providers, to address the needs of victims of family violence, domestic violence, and dating violence, and for those who are members of racial and ethnic minority populations and underserved populations (See Section 10407(a)(2)).
To serve victims most in need and to comply with Federal law, services must be widely accessible to all. Service providers must not discriminate on the basis of age, disability, sex, race, color, national origin, or religion (Section 10406(c)(2)). The HHS Office for Civil Rights provides guidance to grantees complying with these requirements.
States should use the following definitions in carrying out their programs (Section 10402).
• Meet the needs of victims of family violence, domestic violence, or dating violence, and their dependents, for short-term, transitional, or long-term safety; and
• Provide counseling, advocacy, or assistance for victims of family violence, domestic violence, or dating violence, and their dependents.
For FY 2013, HHS will make available for grants to designated State agencies 70 percent of the amount appropriated under section 10403(a)(1) of FVPSA, which is not reserved under Section 10403(a)(2). In FY 2012, ACYF awarded $90,682,686 to State agencies for these purposes. In separate announcements, ACYF will allocate 10 percent of the foregoing appropriation to tribes and tribal organizations for the establishment and operation of shelters, safe houses, and the provision of supportive services; and 10 percent to the State Domestic Violence Coalitions to continue their work within the domestic violence community by providing technical assistance and training, needs assessment, and advocacy services, among other activities with local domestic violence programs, and to encourage appropriate responses to domestic violence within the States. Six percent of the amount appropriated under section 10403(c) of FVPSA, and reserved under section 10403(a)(2)(c), will be available in FY 2013 to continue the support for the two National Resource Centers (NRCs), four Special Issue Resource Centers (SIRCs), and the three Culturally Specific Special Issue Resource Centers (CSSIRCs). Additionally, funds appropriated under FVPSA will be used to support other activities, including training and technical assistance, collaborative projects with advocacy organizations and service providers, data collection efforts, public education activities, research and other demonstration projects, as well as the ongoing operation of the National Domestic Violence Hotline.
FVPSA grants to the States, the District of Columbia, and the Commonwealth of Puerto Rico are based on a population formula. Each State grant shall be $600,000, with the remaining funds allotted to each State on the same ratio as the population of the State to the population of all States (Section 10405(a)(2)). State populations are determined on the basis of the most recent census data available to the Secretary of HE–IS, and the Secretary shall use for such purpose, if available, the annual current interim census data produced by the Secretary of Commerce pursuant to 13 U.S.C. 181.
For the purpose of computing allotments, the statute provides that Guam, American Samoa, the Virgin Islands, and the Commonwealth of the Northern Mariana Islands will each receive grants of not less than one-eighth of one percent of the amount appropriated for formula grants to States (Section 10405(a)(1)).
Grants funded by the States will meet the matching requirements in Section 10406(c)(4). No grant shall be made to any entity other than a State unless the entity agrees that, with respect to the cost to be incurred by the entity in carrying out the program or project for which the grant is awarded, the entity will make available (directly or through donations from public or private entities) non-Federal contributions in an amount that is not less than $1 for every $5 of federal funds provided under the grant. The non-Federal contributions required may be in cash or in kind.
24 Months.
FVPSA funds may be used for expenditures on and after October 1 of each fiscal year for which they are granted and will be available for expenditure through September 30 of the following fiscal year, i.e., FY 2013 funds may be used for expenditures from October 1, 2012, through September 30, 2014; FY 2014 funds from October 1, 2013, through September 30, 2015; and FY 2015 funds from October 1, 2014, through September 30, 2016. Funds will be available for obligations only through FY 2013: September 30, 2014; FY 2014: September 30, 2015 and FY 2015: September 30, 2016, and must be liquidated by FY 2013: December 30, 2014; FY 2014: December 30, 2015; and FY 2015: December 30, 2016.
Re-allotted funds, if any, are available for expenditure until the end of the fiscal year following the fiscal year that the funds became available for re-allotment. FY 2013 grant funds that are made available to the States through re-allotment, under section 10405(d), must be expended by the State no later than September 30, 2014; FY 2014 funds must be expended no later than September 30, 2015; and FY 2015 funds must be expended no later than September 30, 2016.
“States,” as defined in section 10402 of FVPSA, are eligible to apply for funds. The term “State” means each of the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the Virgin Islands, and the Commonwealth of the Northern Mariana Islands.
In the past, Guam, the Virgin Islands, the Commonwealth of the Northern Mariana Islands, and American Samoa have applied for funds as a part of their consolidated grant under the Social Services Block Grant. These jurisdictions need not submit an application under this program announcement if they choose to have their allotment included as part of a consolidated grant application; however, they are required to submit a Performance Progress Report using the standardized format.
Data Universal Numbering System (DUNS) Number is the nine-digit, or thirteen-digit (DUNS + 4), number established and assigned by Dun and Bradstreet, Inc. (D&B) to uniquely identify business entities.
All applicants and sub-recipients must have a DUNS number at the time of application in order to be considered for a grant or cooperative agreement. A DUNS number is required whether an applicant is submitting a paper application or using the Government-wide electronic portal,
The process to request a DUNS Number by telephone will take between 5 and 10 minutes.
The System for Award Management (SAM) at
SAM is the Federal registrant database and repository into which an entity must provide information required for the conduct of business as a recipient. The former CCR Web site is no longer be available. All information previously held in the Central Contractor Registration (CCR) system has been migrated to
Applicants may register at
Applicants are strongly encouraged to register at SAM well in advance of the application due date. Registration at
It can take 24 hours or more for updates to registrations at
See the SAM Quick Guide for Grantees at
• Be registered in at
• Maintain an active registration at
• Provide its active DUNS number in each application or plan it submits to an HHS agency.
ACF is prohibited from making an award to an applicant that has not complied with these requirements. If, at the time of an award is ready to be made, and the intended recipient has not complied with these requirements, ACF:
• May determine that the applicant is not qualified to receive an award; and
• May use that determination as a basis for making an award to another applicant.
Additionally, all first-tier subaward recipients (i.e., direct subrecipients) must have an active DUNS number at the time the subaward is made.
The State's application must be submitted by the chief executive officer of the State and must contain the following information or documentation (Section 10407(a)(1)):
(1) The name and complete address of the State agency; the name and contact information for the official designated as responsible for the administration of FVPSA programs and activities relating to family violence, domestic violence, and dating violence that are carried out by the State and for coordination of related programs within the State; the name and contact information for a contact person if different from the designated official (Section 10407(a)(2)(G)).
(2) A plan describing how the State will involve community-based organizations whose primary purpose is to provide culturally appropriate services to underserved populations, including how such community-based organizations can assist the State in identifying and addressing the unmet needs of such populations, including involvement in the State planning process and other ongoing communications (Section 10407(a)(2)(E)).
(3) A plan describing how the State will provide specialized services including trauma-informed services for children exposed to family violence, domestic violence, or dating violence, underserved populations, and victims who are members of racial and ethnic minority populations (Section 10406(a)(3)).
(4) A plan describing in detail how the needs of underserved populations will be met (Section 10406(a)(3)). “Underserved populations” include populations underserved because of geographic location (such as rural isolation); underserved racial and ethnic populations; populations underserved because of special needs (such as language bathers, disabilities, immigration status, or age); lesbian, gay, bisexual, or transgender (LGBT) individuals; at-risk youth; or victims with disabilities and any other population determined to be underserved by the Statewide needs assessment, the state planning process, or the Secretary of HHS (Section 10402(14)). The State plan should:
(a) Identify which populations in the State are currently underserved, and the process used to identify underserved population; describe those that are being targeted for outreach and services; and provide a brief explanation of why those
(b) Describe the outreach plan, including the domestic violence training to be provided, the means for providing technical assistance and support, and the leadership role played by those representing and serving the underserved populations in question.
(c) Describe the specific services to be provided or enhanced, including new shelters or services, improved access to shelters or services, or new services for underserved populations such as victims from communities of color, immigrant victims, LGBT individuals, adolescents, at-risk youth, or victims with disabilities.
(5) Include a description of how the State plans to use the grant funds; a description of the target populations; the number of shelters to be funded; the number of nonresidential programs to be funded; the services the State's subgrantees will provide; and the expected results from the use of the grant funds as required by Sections 10407(a)(2)(F) and 10408(b).
(6) Describe the plan to assure an equitable distribution of grants and grant funds within the State and between urban and rural areas within such State (Section 10407(a)(2)(C)).
(7) Provide complete documentation of consultation with and participation of the State Domestic Violence Coalition in the State planning process and monitoring of the distribution of grants and the administration of grant programs and projects (Section 10407(a)(2)(D)).
(8) Provide complete documentation of policies, procedures, and protocols that ensure personally identifying information will not be disclosed when providing statistical data on program activities and program services; the confidentiality of records pertaining to any individual provided family violence prevention services by any FVPSA-supported program will be maintained; and the address or location of any FVPSA-supported shelter will not be made public without the written authorization of the person or persons responsible for the operation of such shelter (Sections 10407(a)(2)(A) and 10406(c)(5)).
(9) Provide a copy of the law or procedures, such as a process for obtaining an order of protection, that the State has implemented for the barring of an abuser from a shared household (Section 10407(a)(2)(H)).
(10) Applicants must include a signed copy of the assurances as required by Section 10407(a)(2)(B) (See Appendix A).
Applicants seeking financial assistance under this announcement must submit the listed Standard Forms (SFs), assurances, and certifications. All required Standard Forms and certifications are available at
As required by the Paperwork Reduction Act, 44 U.S.C. 3501–3520, the public reporting burden for the project description is estimated to average 10 hours per response hours per response, including the time for reviewing instructions, gathering and maintaining the data needed, and reviewing the collection of information. The Project Description information collection is approved under OMB control number 0970–0280, which expires November 30, 2014. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
For States, this program is covered under Executive Order 12372, “Intergovernmental Review of Federal Programs,” for State plan consolidation and implication only—45 CFR 100.12. The review and comment provisions of the Executive Order and Part 100 do not apply.
The Consolidated Appropriations Act, 2012 (Pub. L. 112–74), enacted December 23, 2011, limits the salary amount that may be awarded and charged to ACF mandatory and discretionary grants. Award funds issued under this announcement may not be used to pay the salary, or any percentage of salary, to an individual at a rate in excess of Executive Level II. The Executive Level II salary of the Federal Executive Pay scale is $179,700
Costs of organized fund raising, including financial campaigns, endowment drives, solicitation of gifts and bequests, and similar expenses incurred solely to raise capital or obtain contributions, are considered unallowable costs under grants awarded under this announcement. Construction is not an allowable activity or expenditure under this grant award.
Applications should be sent or delivered to: Administration for Children and Families, Administration on Children, Youth and Families, Family and Youth Services Bureau, Family Violence Prevention and Services Program, ATTN: Edna James, 1250 Maryland Avenue SW., Suite 8214, Washington, DC 20024.
The Secretary of HHS will approve any application that meets the requirements of FVPSA and this announcement and will not disapprove any such application except after reasonable notice of the Secretary's intention to disapprove has been provided to the applicant and after a 6-month period providing an opportunity for the applicant to correct any deficiencies. The notice of intention to disapprove will be provided to the applicant within 45 days of the date of the application.
Awards issued under this announcement are subject to the uniform administrative requirements and cost principles of 45 CFR part 74 (Awards And Subawards To Institutions Of Higher Education, Hospitals, Other Nonprofit Organizations, And Commercial Organizations) or 45 CFR part 92 (Grants And Cooperative Agreements To State, Local, And Tribal Governments). The Code of Federal Regulations (CFR) is available at
An application funded with the release of Federal funds through a grant award, does not constitute, or imply, compliance with Federal regulations. Funded organizations are responsible for ensuring that their activities comply with all applicable Federal regulations.
Grantees are also subject to the requirements of 45 CFR 87.1(c), Equal Treatment for Faith-Based Organizations, which says, “Organizations that receive direct financial assistance from the [Health and Human Services] Department under any Department program may not engage in inherently religious activities, such as worship, religious instruction, or proselytization, as part of the programs or services funded with direct financial assistance from the Department.” Therefore, organizations must take steps to completely separate the presentation of any program with religious content from the presentation of the Federally funded program by time or location
A faith-based organization receiving Ill-IS funds retains its independence from Federal, State, and local governments, and may continue to carry out its mission, including the definition, practice, and expression of its religious beliefs. For example, a faith-based organization may use space in its facilities to provide secular programs or services funded with Federal funds without removing religious art, icons, scriptures, or other religious symbols. In addition, a faith-based organization that receives Federal funds retains its authority over its internal governance, and it may retain religious terms in its organization's name, select its board members on a religious basis, and include religious references in its organization's mission statements and other governing documents in accordance with all program requirements, statutes, and other applicable requirements governing the conduct of HHS-funded activities.
Regulations pertaining to the Equal Treatment for Faith-Based Organizations, which includes the prohibition against Federal funding of inherently religious activities, “Understanding the Regulations Related to the Faith-Based and Neighborhood partnerships Initiative” are available at
The Drug-Free Workplace Act of 1988 (41 U.S.C. 8102 et seq.) requires that all organizations receiving grants from any Federal agency agree to maintain a drug-free workplace. By signing the application, the Authorizing Official agrees that the grantee will provide a drug-free workplace and will comply with the requirement to notify ACF if an employee is convicted of violating a criminal drug statute. Failure to comply with these requirements may be cause for debarment. Government-wide requirements for Drug-Free Workplace for Financial Assistance are found in 2 CFR part 182; HHS implementing regulations are set forth in 2 CFR 382.400. All recipients of ACF grant funds must comply with the requirements in Subpart B—Requirements for Recipients Other Than Individuals, 2 CFR 382.225. The rule is available at
HHS regulations published in 2 CFR part 376 implement the government-wide debarment and suspension system guidance (2 CFR part 180) for HHS' non-procurement programs and activities.
The Pro-Children Act of 2001, 20 U.S.C. 7181 through 7184, imposes restrictions on smoking in facilities where federally funded children's services are provided. HHS grants are subject to these requirements only if they meet the Act's specified coverage. The Act specifies that smoking is prohibited in any indoor facility (owned, leased, or contracted for) used for the routine or regular provision of kindergarten, elementary, or secondary education or library services to children under the age of 18. In addition, smoking is prohibited in any indoor facility or portion of a facility (owned, leased, or contracted for) used for the routine or regular provision of federally funded health care, day care, or early childhood development, including Head Start services to children under the age of 18. The statutory prohibition also applies if such facilities are constructed, operated, or maintained with Federal funds. The statute does not apply to children's services provided in private residences, facilities funded solely by Medicare or Medicaid funds, portions of facilities used for inpatient drug or alcohol treatment, or facilities where WIC coupons are redeemed. Failure to comply with the provisions of the law may result in the imposition of a civil monetary penalty of up to $1,000 per violation and/or the imposition of an administrative compliance order on the responsible entity.
States are required to submit an annual performance progress report to ACYF describing the activities carried out and an assessment of the effectiveness of those activities in achieving the purposes of the grant (Section 10406(d)). Further guidance regarding the assessment requirement is included in the PPR. A section of this performance report must be completed by each grantee or subgrantee that provided program services and activities. State grantees should compile subgrantee performance reports into a comprehensive report for submission. A copy of the required PPR can be found at
PPRs for the States and Territories are due on an annual basis at the end of the calendar year (December 29). Grantees should submit their reports online through the Online Data Collection (OLDC) system at the following address:
Please note that section 10407(bX4) of FVPSA requires HHS to suspend funding for an approved application if any State applicant fails to submit an annual PPR or if the funds are expended for purposes other than those set forth under this announcement.
Grantees must submit annual Financial Status Reports (SF–425). The first SF–425A is due December 29, 2013, 2014, and 2015. The final SF–425A is due December 29, 2014, 2015, and 2016. SF–425A can be found at:
Completed reports may be mailed to: Deborah Bell, Division of Mandatory Grants Office of Grants Management Administration for Children and Families, 370 LEnfant Promenade SW., 6th Floor, Washington, DC 20447. Grantees have the option of submitting their reports online through the Online Data Collection (OLDC) system at the following address:
Failure too submit reports on time may be a basis for withholding grant funds, or suspension or termination of the grant. All funds reported as unobligated after the obligation period will be recouped.
Finable versions of the SF–425 form in Adobe PDF and MS-Excel formats, along with instructions, are available at
Awards issued as a result of this funding opportunity may be subject to the Transparency Act subaward and executive compensation reporting requirements of 2 CFR part 170. See ACF's
ACF has implemented the use of the SF–428
Edna James at (202) 205–7750 or
The undersigned grantee certifies that:
(1) Grant funds under the Family Violence Prevention Services Act (FVPSA) will be distributed to local public agencies or nonprofit private organizations (including faith-based and charitable organizations, community-based organizations, and voluntary associations) that assist victims of family violence, domestic violence, or dating violence (as defined in Section 10402(2–4), and their dependents, and have a documented history of effective work concerning family violence, domestic violence, or dating violence (Section 10408(c)).
(2) Grant funds will be used for programs and projects within the State that are designed to prevent incidents of family violence, domestic violence, and dating violence by providing immediate shelter and supportive services and access to community-based programs for adult and youth victims, as well as specialized services for children exposed to domestic violence, underserved populations, and those who are members of racial and ethnic minority populations (as defined in Section 10406(a)(1–3)).
(3) In distributing the funds, the State will give special emphasis to the support of community-based projects of demonstrated effectiveness carried out by non-profit,
(4) Not less than 70 percent of the funds distributed shall be for the primary purpose of providing immediate shelter and supportive services to adult and youth victims of family violence, domestic violence, or dating violence, and their dependents (Section 10408(b)(2)).
(5) Not less than 25 percent of the funds distributed shall be for the purpose of providing supportive services and prevention services as described in Section 10408(b)(2)to victims of family violence, domestic violence, or dating violence, and their dependents).
(6) Not more than 5 percent of the funds will be used for State administrative costs (Section 10407(a)(2)(b)(i)).
(7) The State grantee is in compliance with the statutory requirements of Section 10407(a)(2)(C), regarding the equitable distribution of grants and grant funds within the State and between urban and rural areas within the State.
(8) The State will consult with and provide for the participation of the State Domestic Violence Coalition in the planning and monitoring of the distribution of grant funds and the administration of the grant programs and projects (Section 10407(a)(2)(D)).
(9) Grant funds made available under this program by the State will not be used as direct payment to any victim of family violence, domestic violence, or dating violence, or to any dependent of such victim (Section 10408(d)(1)).
(10) No income eligibility standard will be imposed on individuals with respect to eligibility for assistance or services supported with funds appropriated to carry out the FVPSA (Section 10406(c)(3)).
(11) No fees will be levied for assistance or services provided with funds appropriated to carry out the FVPSA (Section 10406(c)(3)).
(12) The address or location of any shelter or facility assisted under the FVPSA that otherwise maintains a confidential location will, except with written authorization of the person or persons responsible for the operation of such shelter, not be made public (Section 10406(c)(5)(H)).
(13) The applicant has established policies, procedures, and protocols to ensure compliance with the provisions of Section 10406(c)(5) regarding non-disclosure of confidential or private information (Section 10407(a)(2)(A)).
(14) Pursuant to Section 10406(c)(5), the applicant will comply with requirements to ensure the non-disclosure of confidential or private information, which include, but are not limited to: (1) Grantees will not disclose any personally identifying information collected in connection with services requested (including services utilized or denied), through grantee's funded activities or reveal personally identifying information without informed, written, reasonably time-limited consent by the person about whom information is sought, whether for the FVPSA-funded activities or any other Federal or State program and in accordance with Section 10406(c)(5)(B)(ii); (2) grantees will not release information compelled by statutory or court order unless adhering to the requirements of Section10406(c)(5)(C); (3) grantees may share non-personally identifying information in the aggregate for the purposes enunciated in Section 10406(c)(5)(D)(i) as well as for other purposes found in Section 10406(c)(5)(D)(ii) and (iii).
(15) Grants funded by the State in whole or in part with funds made available under the FVPSA will prohibit discrimination on the basis of age, disability, sex, race, color, national origin, or religion (Section 10406(c)(2)).
(16) Funds made available under the FVPSA will be used to supplement and not supplant other Federal, State, and local public funds expended to provide services and activities that promote the objectives of the FVPSA (Section 10406(c)(6)).
(17) Receipt of supportive services under the FVPSA will be voluntary. No condition will be applied for the receipt of emergency shelter as described in Section 10408(d)(2)).
(18) The State grantee has a law or procedure to bar an abuser from a shared household or a household of the abused person, which may include eviction laws or procedures (Section 10407(a)(2)(H)).
As the Authorized Organizational Representative (AOR) signing this application on behalf of
I hereby attest and certify that:
The needs of lesbian, gay, bisexual, transgender, and questioning program participants are taken into consideration in applicant's program design. Applicant considered how its program will be inclusive of and non-stigmatizing toward such participants. If not already in place, awardee and, if applicable, sub-awardees must establish and publicize policies prohibiting harassment based on race, sexual orientation, gender, gender identity (or expression), religion, and national origin. The submission of an application for this funding opportunity constitutes an assurance that applicants have or will put such policies in place within 12 months of the award. Awardees should ensure that all staff members are trained to prevent and respond to harassment or bullying in all forms during the award period. Programs should be prepared to monitor claims, address them seriously, and document their corrective action(s) so all participants are assured that programs are safe, inclusive, and non-stigmatizing by design and in operation. In addition, any sub-awardees or subcontractors:
• Have in place or will put into place within 12 months of the award policies prohibiting harassment based on race, sexual orientation, gender, gender identity (or expression), religion, and national origin;
• Will enforce these policies;
• Will ensure that all staff will be trained during the award period on how to prevent and respond to harassment or bullying in all forms, and;
• Have or will have within 12 months of the award, a plan to monitor claims, address them seriously, and document their corrective action(s).
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either electronic or written comments on the collection of information by June 17, 2013.
Submit electronic comments on the collection of information to
Ila S. Mizrachi, Office of Information Management, Food and Drug Administration, 1350 Piccard Dr., P150–400B, Rockville, MD 20850, 301–796–7726,
Under the PRA (44 U.S.C. 3501–3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
This guidance is intended to assist applicants in developing labeling for outcome claims for drugs that are indicated to treat hypertension. With few exceptions, current labeling for antihypertensive drugs includes only the information that these drugs are indicated to reduce blood pressure; the labeling does not include information on the clinical benefits related to cardiovascular outcomes expected from such blood pressure reduction. However, blood pressure control is well established as beneficial in preventing serious cardiovascular events, and inadequate treatment of hypertension is acknowledged as a significant public health problem. FDA believes that the appropriate use of these drugs can be encouraged by making the connection between lower blood pressure and improved cardiovascular outcomes more explicit in labeling. The intent of the guidance is to provide common labeling for antihypertensive drugs except where differences are clearly supported by clinical data. The guidance encourages applicants to submit labeling supplements containing the new language.
The guidance contains two provisions that are subject to OMB review and approval under the PRA, and one provision that would be exempt from OMB review:
(1) Section IV.C of the guidance requests that the CLINICAL STUDIES section of the Full Prescribing Information of the labeling should include a summary of placebo or active-controlled trials showing evidence of the specific drug's effectiveness in lowering blood pressure. If trials demonstrating cardiovascular outcome benefits exist, those trials also should be summarized in this section. Table 1 in Section V of the guidance contains the specific drugs for which FDA has concluded that such trials exist. If there are no cardiovascular outcome data to cite, one of the following two paragraphs should appear:
“There are no trials of [DRUGNAME] or members of the [name of pharmacologic class] pharmacologic class demonstrating reductions in cardiovascular risk in patients with hypertension,” or “There are no trials of [DRUGNAME] demonstrating reductions in cardiovascular risk in patients with hypertension, but at least one pharmacologically similar drug has demonstrated such benefits.”
In the latter case, the applicant's submission generally should refer to table 1 in section V of the guidance. If the applicant believes that table 1 is incomplete, it should submit the clinical evidence for the additional information to Docket No. FDA–2008–D–0150. The labeling submission should reference the submission to the docket. FDA estimates that no more than one submission to the docket will be made annually from one company, and that each submission will take approximately 10 hours to prepare and submit. Concerning the recommendations for the CLINICAL STUDIES section of the Full Prescribing Information of the labeling, FDA regulations at §§ 201.56 and 201.57 (21 CFR 201.56 and 201.57) require such labeling, and the information collection associated with these regulations is approved by OMB under OMB control number 0910–0572.
(2) Section VI.B of the guidance requests that the format of cardiovascular outcome claim prior approval supplements submitted to FDA under the guidance should include the following information:
1. A statement that the submission is a cardiovascular outcome claim supplement, with reference to the guidance and related Docket No. FDA–2008–D–0150.
2. Applicable FDA forms (e.g., 356h, 3397).
3. Detailed table of contents.
4. Revised labeling:
a. Include draft revised labeling conforming to the requirements in §§ 201.56 and 201.57;
b. Include marked-up copy of the latest approved labeling, showing all additions and deletions, with annotations of where supporting data (if applicable) are located in the submission.
FDA estimates that approximately 20 cardiovascular outcome claim supplements will be submitted annually from approximately 8 different companies, and that each supplement will take approximately 20 hours to prepare and submit. The guidance also recommends that other labeling changes (e.g., the addition of adverse event data) should be minimized and provided in separate supplements, and that the revision of labeling to conform to §§ 201.56 and 201.57 may require substantial revision to the ADVERSE REACTIONS or other labeling sections.
(3) Section VI.C of the guidance states that applicants are encouraged to include the following statement in promotional materials for the drug.
”[DRUGNAME] reduces blood pressure, which reduces the risk of fatal and nonfatal cardiovascular events, primarily strokes and myocardial infarctions. Control of high blood pressure should be part of comprehensive cardiovascular risk management, including, as appropriate, lipid control, diabetes management, antithrombotic therapy, smoking cessation, exercise, and limited sodium intake. Many patients will require more than one drug to achieve blood pressure goals.”
The inclusion of this statement in the promotional materials for the drug would be exempt from OMB review based on 5 CFR 1320.3(c)(2), which
FDA requests public comments on the information collection provisions described in this document and set forth in the following table:
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) has determined that OXYCONTIN (oxycodone hydrochloride) extended-release tablets (10 milligrams (mg), 15 mg, 20 mg, 30 mg, 40 mg, 60 mg, 80 mg, and 160 mg) approved under new drug application (NDA) 20–553 were withdrawn from sale for reasons of safety or effectiveness. The Agency will not accept or approve abbreviated new drug applications (ANDAs) for products that reference NDA 20–553.
Patrick Raulerson, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 6368, Silver Spring, MD 20993–0002, 301–796–3522.
In 1984, Congress enacted the Drug Price Competition and Patent Term Restoration Act of 1984 (Pub. L. 98–417) (the 1984 amendments), which authorized the approval of duplicate versions of drug products under an ANDA procedure. ANDA applicants must, with certain exceptions, show that the drug for which they are seeking approval contains the same active ingredient in the same strength and dosage form as the “listed drug,” which is a version of the drug that was previously approved. ANDA applicants do not have to repeat the extensive clinical testing otherwise necessary to gain approval of a new drug application (NDA).
The 1984 amendments include what is now section 505(j)(7) of the Federal Food, Drug, and Cosmetic Act (21 U.S.C. 355(j)(7)), which requires FDA to publish a list of all approved drugs. FDA publishes this list as part of the “Approved Drug Products With Therapeutic Equivalence Evaluations,” which is known generally as the “Orange Book.” Under FDA regulations, drugs are removed from the list if the Agency withdraws or suspends approval of the drug's NDA or ANDA for reasons of safety or effectiveness or if FDA determines that the listed drug was withdrawn from sale for reasons of safety or effectiveness (21 U.S.C. 355(j)(7)(C); 21 CFR 314.162).
A person may petition the Agency to determine, or the Agency may determine on its own initiative, whether a listed drug was withdrawn from sale for reasons of safety or effectiveness. This determination may be made at any time after the drug has been withdrawn from sale, but must be made before approving an ANDA that refers to the listed drug (§ 314.161 (21 CFR 314.161)). FDA may not approve an ANDA that does not refer to a listed drug.
OXYCONTIN (oxycodone hydrochloride) extended-release tablets, 10 mg, 15 mg, 20 mg, 30 mg, 40 mg, 60 mg, 80 mg, and 160 mg (original OxyContin), are the subject of NDA 20–553, held by Purdue Pharma LP (Purdue) and initially approved on December 12, 1995. A reformulated version of these products, OXYCONTIN (oxycodone hydrochloride) extended-release tablets, 10 mg, 15 mg, 20 mg, 30 mg, 40 mg, 60 mg, and 80 mg (reformulated OxyContin), are the subject of NDA 22–272, also held by Purdue and initially approved on April 5, 2010. Reformulated OxyContin was developed with physicochemical properties that are intended to make the tablet more difficult to manipulate for purposes of abuse or misuse. Both original and reformulated OxyContin are opioid agonist products indicated for the management of moderate to severe pain when a continuous, around-the-clock opioid analgesic is needed for an extended period of time.
In correspondence dated August 10, 2010, Purdue notified FDA that it had ceased shipment of original OxyContin, and FDA subsequently moved original OxyContin to the “Discontinued Drug Product List” section of the Orange Book. On April 16, 2013, FDA approved a supplemental application for reformulated OxyContin, approving changes to the product labeling that describe certain abuse-deterrent properties of the reformulated product.
Several parties have submitted citizen petitions under 21 CFR 10.30, requesting that the Agency determine whether original OXYCONTIN (oxycodone hydrochloride) extended-release tablets were voluntarily withdrawn from sale for reasons other than safety or effectiveness.
Based on the information available at this time, FDA has determined under § 314.161 that original OxyContin was
Opioid analgesics are an important component of modern pain management. Abuse and misuse of these products, however, has grown into a public health epidemic. According to the Centers for Disease Control and Prevention, sales of prescription opioids in the United States increased over 300 percent from 1999 to 2008 (Ref. 1). Overdose deaths involving these products increased commensurately over the same period, from 4,000 to 14,800 (Refs. 1 and 2). In 2008 prescription opioids were involved in more overdose deaths than heroin and cocaine combined (Ref. 3). In 2010 the number of overdose deaths in which prescription opioids were involved rose to 16,651, which represented more than 75 percent of all overdose deaths involving prescription drugs (Ref. 4).
FDA, together with other Federal agencies, is working to address this large and growing problem while ensuring that patients in pain have appropriate access to opioid analgesics. FDA has worked to improve the labeling of OxyContin and other opioid analgesics to better warn prescribers and patients of the serious risks associated with abuse and misuse. FDA also has worked extensively with the sponsors of OxyContin and other extended-release or long-acting prescription (ER/LA) opioid analgesics to address these risks through a classwide risk evaluation and mitigation strategy (REMS)
This REMS, approved on July 9, 2012, requires sponsors of ER/LA opioids to make available training for health care professionals on proper prescribing practices and also to distribute educational materials to prescribers and patients on the safe use of these medications.
FDA considers the development of opioid analgesics that can deter abuse and misuse to be a public health priority. Opioid analgesics can be abused orally or by injection, snorting, or smoking and also may be misused in therapeutic contexts. Products may be designed to deter one or more of these methods of abuse or misuse. Following mandates in the 2011 White House prescription drug abuse prevention plan (Ref. 5) and section 1122(c) of the Food and Drug Administration Safety and Innovation Act (Pub. L. 112–144) (126 Stat. 1075), FDA recently issued a draft guidance to industry on the evaluation and labeling of potentially abuse-deterrent opioid analgesics (Ref. 6).
All forms of opioid analgesic abuse are dangerous, and non-oral routes of abuse are particularly dangerous. Intranasal and intravenous opioid abuse is associated with serious adverse events including addiction, overdose, and death (Refs. 7, 8, and 9). Intravenous opioid abuse is associated with HIV and hepatitis B and C infection risk (Ref. 10). Further, as stated in the OxyContin labeling (see section 9.2), injection of OxyContin excipients “can result in death, local tissue necrosis, infection, pulmonary granulomas, and increased risk of endocarditis and valvular heart injury.” The label is available at
Original OxyContin was often abused by manipulating the product to defeat its extended-release mechanism, causing the oxycodone to be released more rapidly. Original OxyContin also was manipulated for therapeutic purposes, for example, by crushing the product to sprinkle it onto food or to administer it through a gastric tube. As noted in the boxed warning of the labeling, disruption of the tablet and controlled-release mechanism for abuse or misuse “can lead to rapid release and absorption of a potentially fatal dose of oxycodone.”
FDA has conducted an extensive review of data available to the Agency regarding reformulated OxyContin, including in vitro, pharmacokinetic, clinical abuse potential, and postmarketing study data. The data show that, when compared to original OxyContin, reformulated OxyContin has an increased ability to resist crushing, breaking, and dissolution using a variety of tools and solvents. The data also demonstrate that, when subjected to an aqueous environment, reformulated OxyContin gradually forms a viscous hydrogel. The data also indicate that insufflation of finely crushed reformulated OxyContin was associated with lower “liking” compared to finely crushed original OxyContin in recreational opioid users with a history of intranasal drug abuse. FDA concludes, based on these data and our review of all data and information available to the Agency at this time, that the physicochemical properties of reformulated OxyContin are expected to make abuse via injection difficult and are expected to reduce abuse via the intranasal route. In addition, reformulated OxyContin also may deter certain types of misuse in therapeutic contexts.
Additional postmarketing studies intended to assess the impact of reformulated OxyContin on abuse and misuse in the community also have been conducted; some of these are still ongoing. FDA has reviewed the available data from these studies and has concluded that they suggest, but do not confirm, a reduction in non-oral abuse. The Agency will continue to review data from these studies as they become available, as well as any other relevant data that may be developed in the future.
FDA has long considered the abuse potential of a drug in numerous regulatory contexts. Where appropriate, FDA may take into account abuse potential as part of the safety profile of a drug when weighing its benefits and risks. In this case, FDA has considered the abuse potential as part of the Agency's determination of whether the original formulation of OxyContin was withdrawn from sale for reasons of safety or effectiveness. This approach is particularly appropriate here in light of the extensive and well-documented history of OxyContin abuse.
Original OxyContin has the same therapeutic benefits as reformulated OxyContin. Original OxyContin, however, poses an increased potential for abuse by certain routes of administration, when compared to reformulated OxyContin. Based on the totality of the data and information available to the Agency at this time, FDA concludes that the benefits of original OxyContin no longer outweigh its risks. FDA has determined that OXYCONTIN (oxycodone hydrochloride) extended release tablets, 10 mg, 15 mg, 20 mg, 30 mg, 40 mg, 60 mg, 80 mg, and 160 mg (approved under new drug application 20–553), were withdrawn from sale for reasons of safety or effectiveness. Accordingly, the
The following references have been placed on display in the Division of Dockets Management (HFA–305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852, and may be seen by interested persons between 9 a.m. and 4 p.m., Monday through Friday, and are available electronically at
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92–463), notice is hereby given of the following meeting:
Members of the public and interested parties may request to provide comments or register to attend the meeting by emailing their first name, last name, and full email address to
Anyone requesting information regarding the ACICBL should contact Dr. Joan Weiss, Designated Federal Official within the Bureau of Health Professions, Health Resources and Services Administration, in one of three ways: (1) Send a request to the following address: Dr. Joan Weiss, Designated Federal Official, Bureau of Health Professions, Health Resources and Services Administration, Parklawn Building, Room 9C–05, 5600 Fishers Lane, Rockville, Maryland 20857; (2) call (301) 443–6950; or (3) send an email to
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Federal Emergency Management Agency, DHS.
Notice.
The Federal Emergency Management Agency (FEMA), as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on a new information collection. In accordance with the Paperwork Reduction Act of 1995, this notice seeks comments concerning the online registration process for the FEMA Community Drill Day.
Comments must be submitted on or before June 17, 2013.
To avoid duplicate submissions to the docket, please use only one of the following means to submit comments:
(1)
(2)
(3)
All submissions received must include the agency name and Docket ID. Regardless of the method used for submitting comments or material, all submissions will be posted, without change, to the Federal eRulemaking Portal at
Chad Stover, Individual and Community Preparedness Division Program Specialist, FEMA, 202–786–9860 for additional information. You may contact the Records Management Division for copies of the proposed collection of information at facsimile number (202) 646–3347 or email address:
As part of Presidential Policy Directive 8 (PPD–8): National Preparedness, the President tasked the Secretary of Homeland Security to “coordinate a comprehensive campaign to build and sustain national preparedness, including public outreach and community-based and private-sector programs to enhance national resilience.” FEMA intends to conduct one or more Community Drill Days, coordinated nationally by FEMA. Schools, businesses, faith-based organizations, governments at all levels, other community organizations, and families will participate in this Community Drill Day by voluntarily taking part in a simultaneous multi-hazard drill and public education effort.
In order to fulfill its mission, the Federal Emergency Management Agency Individual and Community Preparedness Division; will collect information from individuals and organizations through the Community Drill Day online registration.
FEMA's Individual and Community Preparedness Division would like to create a new online information collection process by which individuals and organizations submit information via a Web site. Registration provides an individual or organization links to educational information and activities about preparedness and response related to specific hazards. Registrants will receive important updates and messages from FEMA. This registry supports the mission of FEMA's Individual and Community Preparedness Division, to help achieve greater community resiliency nationwide.
Comments may be submitted as indicated in the
Federal Emergency Management Agency, DHS.
Notice.
This notice amends the notice of a major disaster declaration for the Navajo Nation (FEMA–4104–DR), dated March 5, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
The notice of a major disaster declaration for the Navajo Nation is hereby amended to include the following area among those areas determined to have been adversely affected by the event declared a major disaster by the President in his declaration of March 5, 2013.
The Navajo Nation and associated lands for buildings and equipment (Category E) under the Public Assistance program.
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of Rhode Island (FEMA–4107–DR), dated March 22, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
Notice is hereby given that, in a letter dated March 22, 2013, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in the State of Rhode Island resulting from a severe winter storm and snowstorm during the period of February 8–9, 2013, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Rhode Island.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. You are further authorized to provide snow assistance under the Public Assistance program for a limited period of time during or proximate to the incident period. Consistent with the requirement that Federal assistance is supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, James N. Russo, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Rhode Island have been designated as adversely affected by this major disaster:
Bristol, Kent, Newport, Providence, and Washington Counties for Public Assistance.
Kent, Providence, and Washington Counties for snow assistance under the Public Assistance program for any continuous 48-hour period during or proximate to the incident period.
All counties within the State of Rhode Island are eligible to apply for assistance under the Hazard Mitigation Grant Program.
(The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.)
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of Maine (FEMA–4108–DR), dated March 25, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
Notice is hereby given that, in a letter dated March 25, 2013, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in certain areas of the State of Maine resulting from a severe winter storm, snowstorm, and flooding during the period of February 8–9, 2013, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Maine.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. You are further authorized to provide snow assistance under the Public Assistance program for a limited period of time during or proximate to the incident period. Consistent with the requirement that Federal assistance is supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, James N. Russo, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Maine have been designated as adversely affected by this major disaster:
Androscoggin, Cumberland, Knox, and York Counties for Public Assistance.
Androscoggin, Cumberland, and York Counties for snow assistance under the Public Assistance program for any continuous 48-hour period during or proximate to the incident period.
Knox County for snow assistance under the Public Assistance program for any continuous 72-hour period during or proximate to the incident period.
All counties within the State of Maine are eligible to apply for assistance under the Hazard Mitigation Grant Program.
(The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households In Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.)
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of Connecticut (FEMA–4106–DR), dated March 21, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
Notice is hereby given that, in a letter dated March 21, 2013, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in the State of Connecticut resulting from a severe winter storm and snowstorm during the period of February 8–11, 2013, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Connecticut.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance, including direct federal assistance, in the designated areas and Hazard Mitigation throughout the State. You are further authorized to provide snow assistance under the Public Assistance program for a limited period of time during or proximate to the incident period. Consistent with the requirement that Federal assistance is supplemental, any Federal funds provided under the Stafford Act for Public Assistance and Hazard Mitigation will be limited to 75 percent of the total eligible costs.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Albert Lewis, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Connecticut have been designated as adversely affected by this major disaster:
Fairfield, Hartford, Litchfield, Middlesex, New Haven, New London, Tolland, and Windham Counties and the Mashantucket Pequot and Mohegan Tribal Nations located within New London County for Public Assistance. Direct federal assistance is authorized.
Fairfield, Litchfield, Middlesex, New London, Tolland, and Windham Counties and the Mashantucket Pequot and Mohegan Tribal Nations located within New London County for snow assistance under the Public Assistance program for any continuous 48-hour period during or proximate to the incident period.
Hartford and New Haven Counties for snow assistance under the Public Assistance program for any continuous 72-hour period during or proximate to the incident period.
All counties and Indian Tribes within the State of Connecticut are eligible to apply for assistance under the Hazard Mitigation Grant Program.
(The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.)
Federal Emergency Management Agency, DHS.
Notice.
This is a notice of the Presidential declaration of a major disaster for the State of State of New Hampshire (FEMA–4105–DR), dated March 19, 2013, and related determinations.
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646–2833.
Notice is hereby given that, in a letter dated March 19, 2013, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121
I have determined that the damage in certain areas of the State of New Hampshire resulting from a severe winter storm and snowstorm during the period of February 8–10, 2013, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of New Hampshire.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance, including direct federal assistance, in the designated areas and Hazard Mitigation throughout the State. You are further authorized to provide snow
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, James N. Russo, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of New Hampshire have been designated as adversely affected by this major disaster:
Belknap, Carroll, Cheshire, Hillsborough, Merrimack, Rockingham, Strafford, and Sullivan Counties for Public Assistance program. Direct federal assistance is authorized.
Belknap, Cheshire, Hillsborough, Merrimack, Rockingham, Strafford, and Sullivan Counties for snow assistance under the Public Assistance program for any continuous 48-hour period during or proximate to the incident period.
Carroll County for snow assistance under the Public Assistance program for any continuous 72-hour period during or proximate to the incident period.
All counties within the State of New Hampshire are eligible to apply for assistance under the Hazard Mitigation Grant Program.
(The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.)
U.S. Customs and Border Protection (CBP), Department of Homeland Security.
60-Day Notice and request for comments; Extension of an existing collection of information: 1651–0083.
As part of its continuing effort to reduce paperwork and respondent burden, CBP invites the general public and other Federal agencies to comment on an information collection requirement concerning the United States-Caribbean Basin Trade Partnership Act (CBTPA). This request for comment is being made pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104–13).
Written comments should be received on or before June 17, 2013, to be assured of consideration.
Direct all written comments to U.S. Customs and Border Protection, Attn: Tracey Denning, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC 20229–1177, at 202–325–0265.
Requests for additional information should be directed to Tracey Denning, U.S. Customs and Border Protection, Regulations and Rulings, Office of International Trade, 90 K Street NE., 10th Floor, Washington, DC 20229–1177, at 202–325–0265.
CBP invites the general public and other Federal agencies to comment on proposed and/or continuing information collections pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104–13). The comments should address: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimates of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden including the use of automated collection techniques or the use of other forms of information technology; and (e) the annual cost burden to respondents or record keepers from the collection of information (total capital/startup costs and operations and maintenance costs). The comments that are submitted will be summarized and included in the CBP request for Office of Management and Budget (OMB) approval. All comments will become a matter of public record. In this document CBP is soliciting comments concerning the following information collection:
This collection of information is provided for by 19 CFR 10.224. CBP Form 450 is accessible at:
Office of the President of Government National Mortgage Association, HUD.
Notice.
The proposed information collection requirement described below will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. HUD is soliciting public comments on the subject proposal.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: Colette Pollard, Q, Administrator Support Specialist, Department of Housing and Urban Development, 451 7th Street SW., Room 4160, Washington, DC 20410; email:
Debra Murphy or Victoria Vargas, Ginnie Mae, 451 7th Street SW., Room B–133, Washington, DC 20410; emails—
HUD will submit the proposed information collection to OMB for review, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35, as amended).
This Notice is soliciting comments from members of the public and affecting agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of the information to be collected; and (4) Minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
This Notice also lists the following information:
The Ginnie Mae Multiclass Securities Program consists of Ginnie Mae Real Estate Mortgage Investment Conduit (“REMIC”) securities, Stripped Mortgage-Backed Securities (“SMBS”), and Platinum securities. The Multiclass Securities program provides an important adjunct to Ginnie Mae's secondary mortgage market activities, allowing the private sector to combine and restructure cash flows from Ginnie Mae Single Class MBS into securities that meet unique investor requirements in connection with yield, maturity, and call-option protection. The intent of the Multiclass Securities Program is to increase liquidity in the secondary mortgage market and to attract new sources of capital for federally insured or guaranteed loans. Under this program, Ginnie Mae guarantees, with the full faith and credit of the United States, the timely payment of principal and interest on Ginnie Mae REMIC, SMBS and Platinum securities.
Sponsors × Frequency per Year = Estimated Annual Frequency.
Estimated Annual Frequency × Estimated Average Completion Time = Estimated Annual Burden Hours.
Status of the proposed information collection: Reinstatement, with change, of a previously approved collection.
Section 3506 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35 as amended.
Office of the Secretary, Interior.
Notice of reopening; request for nominations.
Pursuant to the Claims Resolution Act of 2010, Public Law 111–291, 124 Stat. 3064, and the Class Action Settlement Agreement (“Agreement”),
Nominations must be received on or before May 20, 2013. Assistant Secretary—Indian Affairs Kevin K. Washburn will be hosting a tribal leader call on Monday, April 22, 2013 from 3:00 p.m.–4:00 p.m. to discuss the duties and responsibilities of Board members as well as any questions you may have regarding nominations to the Board. To participate on the call, please dial 1–800–369–2020, passcode 5207626.
Please submit nominations to Lizzie Marsters, Chief of Staff to the Deputy Secretary, Department of the Interior, 1849 C Street NW., Room 6118, Washington, DC 20240 or email to
Lizzie Marsters, Chief of Staff to the Deputy Secretary, at
The Board of Trustees for the Cobell Education Scholarship Fund is being established to fulfill the requirements set forth in the Claims Resolution Act of 2010, Public Law 111–291, 124 Stat. 3064. Specifically, the Claims Resolution Act of 2010 states “the 2 members of the special board of trustees to be selected by the Secretary under paragraph G.3. of the Settlement shall be selected only after consultation with, and after considering the names of possible candidates timely offered by, federally recognized Indian tribes.” Pursuant to the Agreement, the Secretary is to select one non-profit organization among those entities nominated by the Plaintiffs to administer the funds provided for in the Agreement for the Cobell Education Scholarship Fund and to establish a Scholarship Program to provide financial assistance to Native American students to defray the cost of attendance at both post-secondary vocational schools and institutions of higher education. On March 12, 2013, the Secretary of the Interior announced the American Indian College Fund as the non-profit organization. The Board of Trustees shall oversee the management of the Cobell Education Scholarship Fund. The Cobell Education Scholarship Fund was created as an incentive to participate in the Land Buy-Back Program for Indian Nations (Buy-Back Program), the $1.9 billion land consolidation program authorized by the Claims Resolution Act of 2010. The Buy-Back Program contributes up to $60 million of the $1.9 billion to the Cobell Education Scholarship Fund based on the dollar amount of land purchased through the Buy-Back Program. In addition to the maximum $60 million that can be contributed to the Fund, the principal amount of any class member funds in an IIM (Individual Indian Monies) account, for which the whereabouts are unknown and left unclaimed for five years after Final Approval of the Settlement, will be transferred to the organization selected to administer the Cobell Education Scholarship Fund and will be governed by the Board of Trustees. Similarly, any leftover funds from the administration of the Settlement Fund (after all payments under the Settlement are made) will be contributed towards the Cobell Education Scholarship Fund. Assistant Secretary—Indian Affairs Kevin K. Washburn will be hosting a tribal leader call on Monday, April 22, 2013 from 3:00 p.m.–4:00 p.m. to discuss the duties and responsibilities of Board members as well as any questions you may have regarding nominations to the Board. To participate on the call, please dial 1–800–369–2020, passcode 5207626.
Fish and Wildlife Service, Interior.
Notice of availability; request for comments.
In accordance with the Marine Mammal Protection Act of 1972, as amended (MMPA), and its implementing regulations, we, the U.S. Fish and Wildlife Service (Service), have developed a draft revised marine mammal stock assessment report (SAR) for the Pacific walrus stock and for each of the following three northern sea otter stocks in Alaska: Southwest, Southcentral, and Southeast. We now make the SARs available for public review and comment.
Comments must be received by July 17, 2013.
•
•
Please indicate to which revised stock assessment report(s)—the Pacific walrus, or the southeast, southcentral, or southwest Alaska northern sea otter stock—your comments apply. We will not accept email or faxes. We will post all comments on
Charles S. Hamilton, Marine Mammals Management Office, 800–362–5148 (telephone). Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service at 800–877–8339.
We announce for review and comment the availability of draft revised marine mammal stock assessment reports (SAR) for the Pacific walrus (
Under the MMPA (16 U.S.C. 1361 et seq.) and its implementing regulations in the Code of Federal Regulations (CFR) at 50 CFR part 18, we regulate the taking, possession, transportation, purchasing, selling, offering for sale, exporting, and importing of marine mammals. One of the goals of the MMPA is to ensure that stocks of marine mammals occurring in waters under U.S. jurisdiction do not experience a level of human-caused mortality and serious injury that is likely to cause the stock to be reduced below its optimum sustainable population level (OSP). OSP is defined under the MMPA as “* * * the number of animals which will result in the maximum productivity of the population or the species, keeping in mind the carrying capacity of the habitat and the health of the ecosystem of which they form a constituent element” (16 U.S.C. 1362(3)(9)).
To help accomplish the goal of maintaining marine mammal stocks at their OSPs, section 117 of the MMPA requires the Service and the National Marine Fisheries Service (NMFS) to prepare a SAR for each marine mammal stock that occurs in waters under U.S. jurisdiction. Each SAR must include:
1. A description of the stock and its geographic range;
2. A minimum population estimate, maximum net productivity rate, and current population trend;
3. An estimate of human-caused mortality and serious injury;
4. A description of commercial fishery interactions;
5. A categorization of the status of the stock; and
6. An estimate of the potential biological removal (PBR) level.
The MMPA defines the PBR as “the maximum number of animals, not including natural mortalities, that may be removed from a marine mammal stock while allowing that stock to reach or maintain its OSP” (16 U.S.C. 1362(3)(20)). The PBR is the product of the minimum population estimate of the stock (N
Section 117 of the MMPA requires the Service and NMFS to review the SARs (a) At least annually for stocks that are specified as strategic stocks, (b) at least annually for stocks for which significant new information is available, and (c) at least once every 3 years for all other stocks. If our review of the status of a stock indicates that it has changed or may be more accurately determined, then the SAR must be revised accordingly.
A
The Pacific walrus SAR was last revised in December of 2009. In the final 2009 revised stock assessment, we classified the Pacific walrus as a strategic stock because the total human-caused mortality or removals exceeded PBR. Therefore, the Service has reviewed the stock assessment for the Pacific walrus annually and, in 2010, concluded that revision of the SAR was not warranted at that time because the status of the stock had not changed significantly, nor could it be more
The following table summarizes the information we are now making available in the draft revised stock assessment reports for the Pacific walrus and the southwest, southcentral and southeast stocks of the northern sea otter, which lists the stock's N
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
In accordance with section 117(b)(1) of the MMPA, we include in this notice a list of the sources of information or published reports upon which we based the draft revised SAR. The Service consulted technical reports, conference proceedings, refereed journal publications, and scientific studies prepared or issued by Federal agencies, nongovernmental organizations, and individuals with expertise in the fields of marine mammal biology and ecology, population dynamics, Alaska Native subsistence use of marine mammals, modeling, and commercial fishing technology and practices.
These agencies and organizations include: the Service, the U.S. Geological Survey, the National Oceanic and Atmospheric Administration, the National Park Service, the Arctic Institute, the North American Wildlife and Natural Resource Conference, the Marine Mammals of the Holarctic V Conference, the Aleutian Islands Risk Assessment Management Team, the
A complete list of citations to the scientific literature relied on for each of the four draft revised SARs is available on the Federal eRulemaking portal (
In the past, the Service has published a complete list of citations to each technical report, scientific paper, and journal publication upon which the draft revised SAR is based at the end of the Notice of Availability. However, in order for the public to more easily understand how the agency has used and interpreted the sources relied upon in the draft revised SARs, the Service is making the complete list of literature citations available at the end of each of the draft revised SARs. In recognition that the public typically reviews our draft SARs, or any revision thereof, in conjunction with the list of supporting literature citations found at the end of draft SARs, the Service believes it is unnecessary to also publish the complete list of references separately in this notice of availability. Instead, we are including the complete list of references in the draft revised SARs as a single document available to the public through the Government's regulations portal and our own Web page.
The authority for this action is the Marine Mammal Protection Act of 1972, as amended (16 U.S.C. 1361 et al.).
Fish and Wildlife Service, Interior.
Notice of receipt of applications for permit.
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications to conduct certain activities with endangered species, marine mammals, or both. With some exceptions, the Endangered Species Act (ESA) and Marine Mammal Protection Act (MMPA) prohibit activities with listed species unless Federal authorization is acquired that allows such activities.
We must receive comments or requests for documents on or before May 20, 2013. We must receive requests for marine mammal permit public hearings, in writing, at the address shown in the
Brenda Tapia, Division of Management Authority, U.S. Fish and Wildlife Service, 4401 North Fairfax Drive, Room 212, Arlington, VA 22203; fax (703) 358–2280; or email
Brenda Tapia, (703) 358–2104 (telephone); (703) 358–2280 (fax);
Send your request for copies of applications or comments and materials concerning any of the applications to the contact listed under
Please make your requests or comments as specific as possible. Please confine your comments to issues for which we seek comments in this notice, and explain the basis for your comments. Include sufficient information with your comments to allow us to authenticate any scientific or commercial data you include.
The comments and recommendations that will be most useful and likely to influence agency decisions are: (1) Those supported by quantitative information or studies; and (2) Those that include citations to, and analyses of, the applicable laws and regulations. We will not consider or include in our administrative record comments we receive after the close of the comment period (see
Comments, including names and street addresses of respondents, will be available for public review at the street address listed under
To help us carry out our conservation responsibilities for affected species, and in consideration of section 10(a)(1)(A) of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the radiated tortoise (
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the scimitar-horned oryx (
The applicant requests a permit authorizing interstate and foreign commerce, export, and cull of excess scimitar-horned oryx (
The applicant requests renewal of their captive-bred wildlife registration under 50 CFR 17.21(g) for the following families, and species, to enhance their propagation or survival. This notification covers activities to be conducted by the applicant over a 5-year period.
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the radiated tortoise (
The applicant requests renewal and amendment of their captive-bred wildlife registration under 50 CFR 17.21(g) for the following families, genera, and species, to enhance their propagation or survival. This notification covers activities to be conducted by the applicant over a 5-year period.
The applicant requests renewal of their captive-bred wildlife registration under 50 CFR 17.21(g) for the golden parakeet (
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the scimitar-horned oryx (
The applicant requests amendment of their captive-bred wildlife registration under 50 CFR 17.21(g) to include the following black rhinoceros (
The applicant requests renewal and amendment of their captive-bred wildlife registration under 50 CFR 17.21(g) for the following families, genera, and species, to enhance their propagation or survival. This notification covers activities to be conducted by the applicant over a 5-year period.
The applicant requests renewal of their captive-bred wildlife registration under 50 CFR 17.21(g) for the ring-tailed lemur (
The applicant requests renewal of their captive-bred wildlife registration under 50 CFR 17.21(g) for the Amur tiger (
The applicant requests renewal of a permit to export/re-export captive-bred/captive hatched and wild live specimens, captive-bred/wild collected viable eggs, biological samples and salvaged materials from captive-bred/wild specimens of whooping cranes (
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the cheetah
The following applicants each request a permit to import the sport-hunted
The applicant requests a permit to take West Indian manatees (
Concurrent with publishing this notice in the
United States Geological Survey (USGS), Interior.
Notice of an extension of an information collection (1028–0097); request for comments.
To comply with the Paperwork Reduction Act of 1995 (PRA), we are notifying the public that we will submit to OMB an information collection (IC) to renew approval of the paperwork requirements for “National Institutes for Water Resources (NIWR) USGS Competitive Grant Program.” This notice provides the public and other Federal agencies an opportunity to comment on the paperwork burden of this form. This collection is scheduled to expire on July 31, 2013.
You must submit comments on or before June 17, 2013.
Send your comments to the IC to David Govoni, Information Collections Clearance Officer, U.S. Geological Survey, 12201 Sunrise Valley Drive, MS 807, Reston, VA 20192 (mail); (703) 648–7195 (fax); or
Earl Greene, Acting Chief, Office of External Research, U.S. Geological Survey, 5522 Research Park Drive, Baltimore, MD 21228, email:
The Water Resources Research Act of 1984, as amended (42 U.S.C. 10301 et seq.), authorizes a research institute water resources or center in each of the 50 states, the District of Columbia, Puerto Rico, the U.S. Virgin Islands, Guam, the Federated States of Micronesia, the Commonwealth of the Northern Marina Islands, and American Samoa. There are currently 54 such institutes, one in each state, the District of Columbia, Puerto Rico, the U.S. Virgin Islands, and Guam. The institute in Guam is a regional institute serving Guam, the Federated States of Micronesia, and the Commonwealth of the Northern Mariana Islands. Each of the 54 institutes submits an annual application for an allotment grant and provides an annual report on its activities under the grant. The State Water Resources Research Institute Program issues an annual call for applications from the institutes to support plans to promote research, training, information dissemination, and other activities meeting the needs of the States and Nation. The program also encourages regional cooperation among institutes in research into areas of water management, development, and conservation that have a regional or national character. The U.S. Geological Survey has been designated as the administrator of the provisions of the Act.
Please note that the comments submitted in response to this notice are a matter of public record. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment, including your personal identifying information, may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that it will be done.
Department of the Interior, U.S. Geological Survey.
Notice; request for comments on draft National Shoreline Data Content Standard.
The Federal Geographic Data Committee (FGDC) is conducting a public review of the draft National Shoreline Data Content Standard.
The FGDC has developed a draft National Shoreline Data Content Standard that provides a framework for shoreline data development, sharing of data, and shoreline data transformation and fusion. The FGDC Coastal and Marine Spatial Data Subcommittee, chaired by the National Oceanic and Atmospheric Administration (NOAA), sponsored development of the draft standard. The FGDC Coordination Group, comprised of representatives of Federal agencies, has approved releasing this draft standard for public review and comment.
The draft National Shoreline Data Content Standard defines attributes or elements that are common for shoreline data development and provides suggested domains for the elements. The functional scope includes definition of data models, schemas, entities, relationships, definitions, and crosswalks to related standards. The draft National Shoreline Data Content Standard is intended to enhance the shoreline framework by providing technical guidance on shoreline semantics, data structures and their relationships to builders and users of shoreline data. The geographical scope of the draft standard comprises all shorelines of navigable waters within the United States and its territories.
The primary intended users of the National Shoreline Data Content Standard are the mapping, shoreline engineering, coastal zone management, flood insurance, and natural resource management communities. The FGDC invites all stakeholders to comment on this draft standard to ensure that it meets their needs.
The draft National Shoreline Data Content Standard may be downloaded from
Comments that concern specific issues/changes/additions may result in revisions to the National Shoreline Data Content Standard. Reviewers may obtain information about how comments were addressed upon request. After formal endorsement of the standard by the FGDC, the National Shoreline Data Content Standard and a summary analysis of the changes will be made available to the public on the FGDC Web site,
Comments on the draft Coastal and Marine Ecological Classification Standard must be submitted by no later than July 31, 2013.
Ms. Julie Binder Maitra, U.S. Geological Survey, Federal Geographic Data Committee,
The location of our national shoreline is fundamental for legal boundaries, developing nautical charts, and engaging in marine planning and other academic research and commercial activities. Shoreline is a commonly referenced feature, but one that includes multiple definitions and is difficult to precisely map and keep up-to-date. Effective use of shoreline data requires a highly defined logical data structure that is interoperable, efficient and applicable to a broad base of government and private sector uses. Current practices have led to a highly variable shoreline data infrastructure. The National Shoreline Data Content Standard is intended to enhance the shoreline framework by providing technical guidance on shoreline semantics, data structures and their relationships to builders and users of shoreline data.
Shoreline definition protocols currently limit agencies and organizations from effectively sharing and using shoreline coincident data. Agencies have expressed an interest for greater harmonization and uniformity to shoreline data content. Enhancing shoreline content and interoperability is technically feasible and timely in relation to hydrographic, hydrologic and other related standards development. The proposed standard will tie related protocols and existing content together in a new model using recognized reference material, definitions, semantics, and structures. Harmonizing shoreline content will lead to cost savings by reducing the time in design, data re-use, training, and implementation. In addition, harmonizing shoreline data content will assist in areas such as coastal research, historical shoreline change analysis, shoreline change prediction analysis, and the effects of relative sea level change. The National Shoreline Data Content Standard provides a framework for shoreline data development, sharing of data, and shoreline data transformation and fusion. The standard defines attributes or elements that are common for shoreline data development and provides suggested domains for the elements.
The geographical scope of the National Shoreline Data Content Standard comprises all shorelines of navigable waters within the United States and its territories. Navigable waters provide a channel for commerce and transportation of people and goods and as such are under the jurisdiction of the Federal Government.
The functional scope of the standard includes the definition of data models, schemas, entities, relationships, definitions, and crosswalks to related standards. Data discovery, transmittal, display, and delivery are not currently part of this standard.
The primary intended users of this standard are the mapping, shoreline engineering, coastal zone management, flood insurance, and natural resource management communities. The standard is intended to support the shoreline community in developing shoreline data to support data transformation, data fusion, and data sharing.
The FGDC coordinates the development of the National Spatial Data Infrastructure (NSDI), which encompasses the policies, standards, and procedures for organizations to cooperatively produce and share geospatial data. Federal agencies that make up the FGDC develop the NSDI in cooperation with organizations from State, local and tribal governments, the academic community, and the private sector. The authority for the FGDC is OMB Circular No. A–16 Revised on Coordination of Geographic Information and Related Spatial Data Activities (Revised August 19, 2002). More information on the FGDC and the NSDI is available at
Bureau of Indian Affairs, Interior.
Notice of submission to OMB.
In compliance with the Paperwork Reduction Act of 1995, the Assistant Secretary—Indian Affairs is seeking comments on the renewal of Office of Management and Budget (OMB) approval for the collection of information for grants under the Office of Indian Energy and Economic Development, Energy and Mineral Development Program, authorized by OMB Control Number 1076–0174. This information collection expires April 30, 2013.
Interested persons are invited to submit comments on or before May 20, 2013.
You may submit comments on the information collection to the Desk Officer for the Department of the Interior at the Office of Management and Budget, by facsimile to (202) 395–5806 or you may send an email to:
Division of Energy and Mineral Development, Dawn Charging, Senior Policy Analyst, 13922 Denver West Parkway, Suite 200, Lakewood, CO 80401. Email:
The Energy Policy Act of 2005, 25 U.S.C. 3502(a)(2)(B) authorizes the Secretary of the Interior to provide grants to assist Indian tribes in the development of energy resources and further the goal of Indian self-determination.
The Office of Indian Energy and Economic Development (IEED) administers and manages the energy resource development grant program under the Energy and Minerals Development Program (EMDP). Congress may appropriate funds to EMDP on a year-to-year basis. When funding is available, IEED may solicit proposals for energy resource development projects from Indian tribes and tribal energy resource development organizations for use in carrying out projects to promote the integration of energy resources, and to process, use or develop those energy resources on Indian land. The projects may be in the areas of exploration, assessment, development, feasibility, or market studies. Indian tribes that would like to apply for an EMDP grant must submit an application that includes certain information, and must assist IEED by providing information in support of any National Environmental Policy Act (NEPA) analyses.
The Bureau of Indian Affairs (BIA) requests your comments on this collection concerning: (a) The necessity of this information collection for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) The accuracy of the agency's estimate of the burden (hours and cost) of the collection of information, including the validity of the methodology and assumptions used; (c) Ways we could enhance the quality, utility, and clarity of the information to be collected; and (d) Ways we could minimize the burden of the collection of the information on the respondents.
Please note that an agency may not conduct or sponsor, and an individual need not respond to, a collection of information unless it displays a valid OMB Control Number.
It is our policy to make all comments available to the public for review at the location listed in the
Bureau of Land Management, Interior.
Notice of Conference Call Meeting.
In accordance with the Federal Land Policy and Management Act and the Federal Advisory Committee Act, the Bureau of Land Management's (BLM) Utah Resource Advisory Council (RAC) will host a conference call meeting.
The Utah RAC will host a conference call meeting Thursday, May 16, 2013, from 10:00 a.m.–noon, MST.
Those attending in person must meet at the BLM, Utah State Office, 440 West 200 South, Salt Lake City, Utah, in the Monument Conference Room on the fifth floor. The conference call will be recorded for purposes of minute-taking.
If you wish to listen to the teleconference, orally present material during the teleconference, or submit written material for the Council to consider during the teleconference, notify Sherry Foot, Special Programs Coordinator, Bureau of Land Management, Utah State Office, 440 West 200 South, Suite 500, Salt Lake City, Utah 84101; phone 801–539–4195; or,
The RAC formed a subgroup to look at ways to constructively suggest improvements to the BLM-Utah National Landscape Conservation System Strategy. Results of their findings will be presented to the BLM-Utah and the RAC. A public comment period will take place immediately following the presentation. The meeting is open to the public; however, transportation, lodging, and meals are the responsibility of the participating individuals.
Approved:
Notice is hereby given pursuant to the Antitrust Procedures and Penalties Act, 15 U.S.C. 16(b)–(h), that a proposed Final Judgment, Stipulation and Competitive Impact Statement have been filed with the United States District Court for the District of Columbia in
Copies of the Complaint, proposed Final Judgment and Competitive Impact Statement are available for inspection at the Department of Justice, Antitrust Division, Antitrust Documents Group, 450 Fifth Street NW., Suite 1010, Washington, DC 20530 (telephone: 202–514–2481), on the Department of Justice's Web site at
Public comment is invited within 60 days of the date of this notice. Such comments and responses thereto, will be filed with the Court and posted on the U.S. Department of Justice, Antitrust Division's Web site, and, under certain circumstances published in the
The United States of America, acting under the direction of the Attorney General of the United States, brings this civil action to enjoin the acquisition of Permian Mud Service, Inc., (“Permian”), by Ecolab Inc. (“Ecolab”), and to obtain other equitable relief. The United States complains and alleges as follows:
1. Ecolab's acquisition of Permian would combine the two leading providers of production chemical management services for deepwater oil and gas wells (“deepwater PCMS”) in the U.S. Gulf of Mexico (“Gulf”). Deepwater PCMS providers design, produce, and apply specially formulated chemical solutions to oil or gas wells to facilitate hydrocarbon production and protect well infrastructure.
2. Permian's wholly owned subsidiary, Champion Technologies, Inc. (“Champion”), and Ecolab's wholly-owned subsidiary, Nalco Company (“Nalco”), are the two largest suppliers of deepwater PCMS in the Gulf and vigorously compete head-to-head to win the business of oil and gas exploration and production companies (“E&P companies”). If the transaction is allowed to proceed, this competition will be lost and the merged firm will control approximately 70% of the market, leading to higher prices, reduced service quality, and diminished innovation.
3. Accordingly, as alleged more specifically below, the acquisition, if consummated, would likely substantially lessen competition in violation of Section 7 of the Clayton Act, as amended, 15 U.S.C. 18.
4. Ecolab is a Delaware corporation headquartered in St. Paul, Minnesota. Nalco, its wholly-owned subsidiary, is headquartered in Naperville, Illinois and supplies the oil and gas industry with deepwater PCMS through its Energy Services Division. Ecolab generated $1.87 billion in revenues from oil and gas-related products and services in 2011. Nalco is currently the largest supplier of deepwater PCMS in the Gulf.
5. Permian is a Texas corporation headquartered in Houston, Texas. Permian provides specialty chemicals and services to the oil and gas industry and generated $1.25 billion in revenues in 2011. Permian's wholly-owned subsidiary, Champion, is also a Texas corporation and is currently the second largest provider of deepwater PCMS in the Gulf.
6. Pursuant to an agreement dated October 11, 2012, Ecolab agreed to purchase Permian for $2.2 billion. The Defendants amended the Agreement and Plan of Merger on November 28, 2012 (“First Amendment”), on November 30, 2012 (“Second Amendment”) to exclude certain assets and adjust the purchase price to $2.16 billion, and again on December 28, 2012 (“Third Amendment”).
7. The United States brings this action pursuant to Section 15 of the Clayton Act, as amended, 15 U.S.C. 25, to prevent and restrain Defendants from violating Section 7 of the Clayton Act, 15 U.S.C. 18.
8. Ecolab and Permian provide deepwater PCMS in the flow of interstate commerce and their provision of deepwater PCMS substantially affects interstate commerce. The Court has subject matter jurisdiction over this action pursuant to Section 15 of the Clayton Act, 15 U.S.C. 25, and 28 U.S.C. 1331, 1337(a), and 1345.
9. Ecolab and Permian have consented to venue and personal jurisdiction in this judicial district.
10. E&P companies rely on the services of deepwater PCMS providers to facilitate the safe and efficient production of oil and gas from deepwater wells in the Gulf. Throughout the production process, deepwater PCMS providers treat wells with blends of chemicals to prevent naturally occurring material, such as scale, paraffin, and hydrates, from blocking the flow of hydrocarbons to the production platform; protect the well's infrastructure from corrosion and damage; enable the E&P company to efficiently separate the mix of oil, water, and gas produced by the well; and remove or neutralize unwanted substances, such as hydrogen sulfide gas, from the production.
11. Although onshore and shallow water wells also require PCMS, deepwater wells (wells drilled in water depths greater than 1,000 feet) generally present challenging production issues due to the complex infrastructure of many deepwater wells and the high temperatures and pressures often found in deepwater wells.
12. Due to the time and expense required to construct a new production platform in deepwater, E&P companies frequently opt to build “subsea wells,” which can connect to existing offshore production platforms up to 70 miles away, instead of “dry-tree” wells, which must be stationed very close to the production platform. Deepwater PCMS providers must deliver chemicals to subsea wellbores through “umbilicals,” which are clusters of extremely narrow chemical injection, hydraulic, and fiber-optic lines that extend from the production platform to the well. Because of the complexities of this delivery system and the expense of repairing a chemical line clogged by impure or unstable chemicals, E&P companies impose strict qualification and quality control requirements on chemicals administered through umbilicals.
13. Strings of narrow piping called “flow lines” transport oil and gas from a subsea well to the production platform. Because flow lines run along the seafloor, they expose the produced oil, water, and gas to cold temperatures that cause solids to form and block the flow line. Deepwater PCMS providers must specially formulate chemicals for deepwater subsea wells that inhibit the formation or accumulation of solids during prolonged exposure to seafloor temperatures.
14. Deepwater wells often share characteristics that complicate production (
15. A deepwater PCMS provider needs a strong staff of experts to successfully compete in the deepwater Gulf. E&P customers hire PCMS providers to assess and solve their production challenges and continuously manage the well's treatment. They expect PCMS providers to have highly trained and knowledgeable employees to monitor each well on an ongoing basis, devise new treatment programs when circumstances change, and prepare recommendations for potential opportunities. PCMS providers also require subject matter experts who can develop new products and technologies that are effective in whatever novel environments E&P companies operate.
16. E&P companies typically procure deepwater PCMS through a formal or informal bidding process. Potential suppliers are asked to submit a proposal including the recommended treatment plan; test results to support the treatment plan; prices; past experiences with similar well-conditions; safety records; information on the company's supply chain, training programs, lab facilities, and R&D programs; and the resumés or experience levels of proposed service personnel.
17. Customers choose a PCMS provider based on a number of factors, including, but not limited to, the efficacy of the proposed treatment program, price, the provider's prior track record servicing deepwater wells, and the provider's ability to offer timely and competent service. Customers also consider the provider's research and development (“R&D”) program and ability to advise on the optimal well design of new projects.
18. Although deepwater PCMS represents a fraction of an E&P company's overall cost of production, the costs associated with delay or failure are high. If the deepwater PCMS provider selects the wrong chemicals or fails to adequately monitor or service the well, it can cost the customer millions in lost production or compromise the well's infrastructure.
19. Because of the value of deepwater wells and the risks of improper treatment, some customers will only accept a bid for a particular project from a supplier whom it has thoroughly vetted and pre-qualified. As a result, deepwater PCMS providers sometimes compete to be designated as preferred or pre-qualified suppliers. Preferred suppliers may then bid against each other for specific projects.
20. There are often only two or three bidders for each deepwater PCMS contract in the Gulf, and the bidders typically know whom they are competing against for a particular project. Nalco and Champion are the two largest deepwater PCMS providers in the Gulf and compete head-to-head on a substantial number of deepwater PCMS opportunities.
21. The provision of deepwater PCMS is a relevant product market and line of commerce under Section 7 of the Clayton Act. E&P companies are unlikely to forego use of PCMS providers or switch to PCMS providers that only have experience onshore or in shallow water in response to a small but significant and non-transitory increase in deepwater PCMS prices.
22. The risks of not using a PCMS provider, or using a PCMS provider without deepwater operations or experience, greatly outweigh the potential cost savings. Deepwater wells present unique production issues and operational challenges. The costs of a clogged umbilical line are substantial,
23. Deepwater PCMS are not reasonably interchangeable with onshore or shallow water PCMS. Because deepwater basins have unique characteristics and well infrastructure, providers of onshore or shallow water PCMS typically do not have the relevant know-how and experience required to effectively treat deepwater wells. Although there are some subsea wells in shallow water, they are typically closer to the production platform than deepwater subsea wells, so the operational difficulties engendered by umbilicals and flow lines are often less severe in shallow water. Additionally, the geological characteristics of shallow-water areas of the Gulf differ from its deepwater areas, so PCMS providers active in shallow water do not have the same familiarity or experience with the formation rocks or hydrocarbons found in deepwater. Importantly, because deepwater operations differ, onshore and shallow water PCMS providers also typically lack a complete suite of chemicals that can tolerate umbilical injection or the high pressures and temperatures typically found in deepwater wells and the necessary lab and filtration equipment to develop and qualify a chemical for umbilical injection or deepwater use.
24. The U.S. Gulf of Mexico is a relevant geographic market for the provision of deepwater PCMS under Section 7 of the Clayton Act. E&P companies operating in the Gulf are unlikely to switch to a PCMS provider without local infrastructure or Gulf-specific deepwater experience and expertise in the event of a small but significant and non-transitory increase in price.
25. E&P companies operating deepwater wells in the Gulf require their PCMS suppliers to have local infrastructure, such as distribution centers, blending facilities, analytical laboratories and sales and technical personnel, so that the PCMS provider can have the resources it needs nearby to monitor the well and quickly address production challenges. These E&P companies will not select a deepwater PCMS provider that lacks the Gulf-based infrastructure necessary to effectively service their projects.
26. Although experience in another deepwater basin may be relevant to deepwater Gulf operations, each deepwater basin presents unique production challenges resulting from its unique combination of hydrocarbons, produced water, and geological characteristics. PCMS providers operating in other deepwater basins are unlikely to have the depth of experience with the particular production challenges that frequently affect deepwater wells in the Gulf. Customers are unlikely to entrust their wells to PCMS providers without this essential experience.
27. The defendants are the two largest providers of deepwater PCMS in the Gulf. One additional firm has significant deepwater PCMS experience in the Gulf and regularly competes against Nalco and Champion for deepwater PCMS opportunities. A handful of other firms provide deepwater PCMS but lack the robust track record, requisite personnel, and proven product lines that make Champion and Nalco successful competitors. Additionally, these other firms do not compete for the majority of deepwater PCMS opportunities.
28. The relevant market is highly concentrated and would become more concentrated as a result of the proposed transaction. Based on 2012 revenues, Champion's share of the deepwater PCMS market in the Gulf was 34% while Nalco's was 38%.
29. Concentration in relevant markets is typically measured by the Herfindahl-Hirschman Index (“HHI”).
30. The deepwater PCMS market in the Gulf currently is highly concentrated, with an HHI of over 2,900. The proposed merger would significantly increase the HHI by 2,607, rendering the transaction presumptively anticompetitive.
31. Ecolab's acquisition of Permian would combine their respective subsidiaries, Nalco and Champion, the two leading deepwater PCMS providers in the Gulf, creating a dominant firm with a greater than 70% market share. Nalco and Champion vigorously compete on price, terms of sale, service quality, and product development. They have spurred each other to develop and improve products, performance and technology, and customers have benefitted from this competition. The transaction would eliminate the head-to-head competition between Nalco and Champion to provide deepwater PCMS in the Gulf.
32. Nalco and Champion provide deepwater PCMS to wells with similar production issues in similar water depths and are two of the few firms that have the manpower, technical capabilities and expertise to service the Gulf's most challenging wells. Nalco and Champion routinely bid against each other on the same deepwater projects in the Gulf and are considered by many E&P customers to be close substitutes.
33. Customers differentiate among deepwater PCMS providers on the basis of price, reputation, service quality, product effectiveness, and other factors. Nalco's acquisition of Champion would eliminate many customers' preferred alternative to Nalco and reduce the number of preferred or capable bidders on many projects from three to two. Post-acquisition, Nalco would gain the incentive and ability to profitably raise its bid prices significantly above pre-acquisition levels, reduce its investment in R&D, or provide lower levels of service.
34. The response of the remaining deepwater PCMS firm would not be sufficient to constrain an exercise of market power by Nalco after the acquisition. Having removed its closest substitute for many customers, Nalco
35. Entry by a new PCMS service provider or expansion of existing marginal suppliers would not be timely, likely, and sufficient to prevent the substantial lessening of competition caused by the elimination of Champion as an independent competitor.
36. Successful entry into the provision of deepwater PCMS in the Gulf is difficult, costly, and time consuming. To compete, a deepwater PCMS supplier must have local infrastructure, a full line of production chemicals designed for deepwater use, experienced staff, and a track record of successfully treating deepwater wells in the Gulf. Because of the significant investment E&P companies make in deepwater wells and the high costs of any problem or delay, these firms disfavor the risks of using new suppliers or switching between established suppliers, making it difficult for new PCMS providers to enter the market or grow their business.
37. Developing a track record of successfully treating deepwater wells in the Gulf is arduous and takes substantial time. E&P companies typically avoid the cost and delay involved in evaluating and monitoring a new supplier unless the existing supplier exhibits poor performance over a long period of time. Additionally, many E&P companies refuse to be the first customer to use a new deepwater PCMS provider, while others will only use a deepwater PCMS provider after the provider has developed a track record over a number of years.
38. A potential entrant may also face problems acquiring sufficient manpower to expand its business or enter at all. E&P companies require deepwater PCMS providers to commit a number of personnel with significant deepwater experience to the well, and also expect the provider to staff its laboratories and R&D facilities with deepwater experts. It takes existing deepwater PCMS providers years to train employees before they can accumulate deepwater experience and expertise.
39. Defendants cannot demonstrate cognizable and merger-specific efficiencies that would be sufficient to offset the transaction's anticompetitive effects.
40. The effect of Ecolab's proposed acquisition of Permian if it were consummated, would likely be to lessen substantially competition for deepwater PCMS in the Gulf in violation of Section 7 of the Clayton Act, 15 U.S.C. 18. Unless restrained, the transaction would likely have the following effects, among others:
(a) Competition in the market for deepwater PCMS in the Gulf would be substantially lessened;
(b) prices for deepwater PCMS in the Gulf would increase;
(c) the quality of deepwater PCMS services in the Gulf would decrease; and
(d) innovation in the deepwater PCMS market in the Gulf would diminish.
41. Plaintiff requests that this Court:
(a) Adjudge Ecolab's proposed acquisition of Permian to violate Section 7 of the Clayton Act, 15 U.S.C. 18;
(b) Permanently enjoin and restrain Defendants from consummating the proposed acquisition by Ecolab of Permian or from entering into or carrying out any contract, agreement, plan, or understanding, the effect of which would be to combine Ecolab and Permian;
(c) Award the United States its costs for this action; and
(d) Award the United States such other and further relief as the Court deems just and proper.
Respectfully submitted,
Respectfully submitted,
Plaintiff United States of America (“United States”), pursuant to Section 2(b) of the Antitrust Procedures and Penalties Act (“APPA” or “Tunney Act”), 15 U.S.C. 16(b)-(h), files this Competitive Impact Statement relating to the proposed Final Judgment submitted for entry in this civil antitrust proceeding.
Defendant Ecolab Inc. (“Ecolab”) and Defendant Permian Mud Service, Inc. (“Permian”) entered into an Agreement and Plan of Merger, dated October 11, 2012, pursuant to which Ecolab would acquire Permian (“proposed transaction”). Ecolab's wholly-owned subsidiary, Nalco Company (“Nalco”) and Permian's wholly-owned subsidiary, Champion Technologies, Inc. (“Champion”), compete head-to-head to provide production chemical management services for oil and gas wells drilled in over 1,000 feet of water (“deepwater PCMS”) in the United States Gulf of Mexico (“Gulf”). Nalco and Champion are the two leading providers of deepwater PCMS in the Gulf and together control over 70% of the market.
The United States filed a civil antitrust Complaint on April 8, 2013, seeking to enjoin Ecolab's acquisition of Permian. The Complaint alleges that the proposed transaction is likely to lessen competition substantially for deepwater PCMS in the Gulf in violation of Section 7 of the Clayton Act, 15 U.S.C. 18. This loss of competition is likely to lead to higher prices, reduced service quality, and diminished innovation for deepwater PCMS in the Gulf.
At the same time the Complaint was filed, the United States filed a Hold Separate Stipulation and Order (“Hold Separate”) and proposed Final Judgment, which are designed to eliminate the anticompetitive effects of the transaction. Under the proposed Final Judgment, the terms of which are explained more fully below, Ecolab is required to divest a package of assets that Champion has been using to
The United States and Defendants have stipulated that the proposed Final Judgment may be entered after compliance with the APPA. Entry of the proposed Final Judgment would terminate this action, except that the Court would retain jurisdiction to construe, modify, or enforce the provisions of the proposed Final Judgment and to punish violations thereof.
Ecolab provides products and services to the energy, foodservice, and healthcare, industries. Nalco, its wholly-owned subsidiary, supplies the oil and gas industry with deepwater PCMS through its Energy Services Division, which generated $1.87 billion in revenues in 2011. Nalco is currently the largest provider of deepwater PCMS in the Gulf.
Permian provides specialty chemicals and services to the oil and gas industry through its subsidiaries, which jointly generated $1.25 billion in revenues in 2011. Permian supplies deepwater PCMS through its wholly-owned subsidiary, Champion, which is currently the second largest provider of deepwater PCMS in the Gulf.
Deepwater PCMS providers treat deepwater oil and gas wells with blends of chemicals that prevent naturally occurring material, such as scale, paraffin, and hydrates, from blocking the flow of hydrocarbons to the production platform; protect well infrastructure and equipment from corrosion and damage; enable efficient separation of the mix of oil, water, and gas produced by the well; and remove or neutralize unwanted substances, such as hydrogen sulfide gas, from the production.
Oil and gas exploration and production companies (“E&P companies”), who own and operate oil and gas wells, must purchase production chemical management services to safely and efficiently produce oil and gas from onshore, shallow water, and deepwater wells (those drilled in over 1,000 feet of water). However, the complex infrastructure of deepwater wells often requires deepwater PCMS providers to develop solutions that are generally unnecessary onshore or in shallow water. For instance, due to the time and expense required to construct a new production platform in deepwater, E&P companies frequently opt to build deepwater “subsea wells,” which can connect to existing offshore production platforms up to 70 miles away, instead of “dry-tree” wells, which must be stationed very close to the production platform.
To service these wells, deepwater PCMS providers must deliver chemicals through “umbilicals,” which are clusters of extremely narrow chemical injection, hydraulic, and fiber-optic lines that extend from the production platform to the well. Because of the complexities of this delivery system and the expense of repairing a chemical line clogged by impure or unstable chemicals, E&P companies impose strict qualification and quality control requirements on chemicals administered through umbilicals.
Strings of narrow piping called “flow lines” transport oil and gas from a subsea well to the production platform. Because flow lines run along the seafloor, they expose the produced oil, water, and gas to cold temperatures that cause solids to form and block the flow line. Deepwater PCMS providers must specially formulate chemicals for deepwater subsea wells that inhibit the formation or accumulation of solids during prolonged exposure to seafloor temperatures.
In addition to these operational complexities, deepwater wells often present challenging production issues stemming from the high pressures and temperatures common in such wells. Each deepwater well has unique characteristics, which PCMS providers must assess to identify production challenges and develop an appropriate treatment plan. Deepwater wells also typically contain large reserves and are more expensive to repair than onshore or shallow water wells.
For these reasons, most E&P companies operating deepwater wells are extremely risk-averse and seek out PCMS providers and personnel with Gulf-specific deepwater experience and expertise to service their wells. They also typically require deepwater PCMS providers to have more sophisticated laboratories, research and development (“R&D”) programs, and supply chain and quality control operations than onshore or shallow water PCMS providers.
The United States alleges that the provision of deepwater PCMS is a line of commerce and a relevant market within the meaning of Section 7 of the Clayton Act. E&P companies are unlikely to forego use of PCMS providers or switch to PCMS providers that only have experience onshore or in shallow water in response to a small but significant and non-transitory increase in deepwater PCMS prices.
The risks of not using a PCMS provider, or using a PCMS provider without deepwater operations or experience, greatly outweigh the potential cost savings. Deepwater PCMS represent a fraction of the overall cost of producing oil and gas from a deepwater well, but improper deepwater PCMS treatment can cost an E&P company millions in lost production or compromise the well's infrastructure. As a result, E&P companies are unlikely to forego use of PCMS providers or switch to PCMS providers that only have experience onshore or in shallow water in response to a small but significant and non-transitory increase in deepwater PCMS prices.
Deepwater PCMS are not reasonably interchangeable with onshore or shallow water PCMS. Because deepwater basins have unique characteristics and well infrastructure, providers of onshore or shallow water PCMS typically do not have the relevant know-how and experience required to effectively treat deepwater wells. Although there are some subsea wells in shallow water, they are typically closer to the production platform than deepwater subsea wells, so the operational difficulties engendered by umbilicals and flow lines are often less severe in shallow water. Additionally, the geological characteristics of shallow-water areas of the Gulf differ from its deepwater areas, so PCMS providers active in shallow water do not have the same familiarity or experience with the formation rocks or hydrocarbons found in deepwater. Importantly, because deepwater operations differ, onshore and shallow water PCMS providers also typically lack a complete suite of chemicals that can tolerate umbilical injection or the high pressures and temperatures typically found in deepwater wells and generally do not have the necessary lab and filtration equipment to develop and qualify a chemical for umbilical injection or deepwater use.
The United States Gulf of Mexico is a relevant geographic market for the provision of deepwater PCMS under Section 7 of the Clayton Act. E&P companies operating in the Gulf are unlikely to switch to a PCMS provider without local infrastructure or Gulf-specific deepwater experience and expertise in the event of a small but significant and non-transitory increase in price.
E&P companies operating deepwater wells in the Gulf require their PCMS suppliers to have local infrastructure, such as distribution centers, blending facilities, analytical laboratories, and sales and technical personnel, so that the PCMS provider can have the resources it needs nearby to monitor the well and quickly address production challenges. These E&P companies will not select a deepwater PCMS provider that lacks the Gulf-based infrastructure necessary to effectively service the E&P companies' projects.
Although experience in another deepwater basin may be relevant to deepwater Gulf operations, each deepwater basin presents unique production challenges resulting from its unique combination of hydrocarbons, produced water, and geological characteristics. PCMS providers operating in other deepwater basins are unlikely to have the depth of experience with the particular production challenges that frequently affect deepwater wells in the Gulf. E&P companies are unlikely to entrust their wells to PCMS providers without this essential experience.
The market for the provision of deepwater PCMS in the Gulf is highly concentrated and would become more concentrated as a result of the proposed transaction. Based on 2012 revenues, a combined Champion and Nalco would control 70% of the market for deepwater PCMS in the Gulf.
The proposed transaction would eliminate the significant head-to-head competition between Nalco and Champion to provide deepwater PCMS in the Gulf. Nalco and Champion frequently compete for the same deepwater opportunities in the Gulf. They have spurred each other to develop and improve products, performance and technology, and customers have benefitted from this competition.
Nalco's acquisition of Champion would eliminate many customers' preferred alternative to Nalco and reduce the number of preferred or capable bidders on many projects from three to two. Post-acquisition, Nalco would gain the incentive and ability to profitably raise its bid prices significantly above pre-acquisition levels, reduce its investment in R&D, or provide lower levels of service.
Entry by a new PCMS service provider or expansion of existing suppliers would not be timely, likely, and sufficient to prevent the substantial lessening of competition caused by the elimination of Champion as an independent competitor.
Successful entry into the provision of deepwater PCMS in the Gulf is difficult, costly, and time-consuming. To compete, a deepwater PCMS supplier must have local infrastructure, a full line of production chemicals designed for deepwater use, experienced staff, and a track record of successfully treating deepwater wells in the Gulf. Because of the significant investment E&P companies make in deepwater wells and the high costs of any problem or delay, these firms disfavor using new suppliers or switching between established suppliers, making it difficult for new deepwater PCMS providers to enter the market or grow their business.
Developing a track record of successfully treating deepwater wells in the Gulf is arduous and takes substantial time. E&P companies typically avoid the cost and delay involved in evaluating and monitoring a new supplier unless the existing supplier exhibits poor performance over a long period of time. Additionally, many E&P companies refuse to be the first customer to use a new deepwater PCMS provider, while others will only use a deepwater PCMS provider after the provider has developed a track record over a number of years.
A new deepwater PCMS provider may also face challenges acquiring sufficient manpower to expand its business or enter at all. E&P companies require deepwater PCMS providers to commit a number of personnel with significant deepwater experience to the well, and also expect the provider to staff its laboratories and R&D facilities with deepwater experts. It takes existing deepwater PCMS providers years to train employees before they can accumulate deepwater experience and expertise.
The proposed Final Judgment will eliminate the likely anticompetitive effects of the merger in the market for deepwater PCMS in the Gulf by establishing a new, independent, and economically viable competitor. The package of divestiture assets provides the acquirer with the assets it needs to establish a significant presence in the Gulf and become an effective competitor, including the tangible and intangible assets that Champion currently uses to provide PCMS to deepwater wells in the Gulf, the option to acquire Champion's storage, distribution, filtration, and quality control facility in Broussard, Louisiana, and a short-term chemical supply agreement that will allow the acquirer to immediately begin supplying Champion customers with the production chemicals they currently use and trust. In addition, because experienced personnel are critical to success in the deepwater PCMS business in the Gulf—and will be even more important to a new entrant seeking to secure the trust and business of risk-averse customers—the divestiture package provides the acquirer with an expansive right to hire relevant Champion personnel without interference from the merged firm.
The overriding goal of the proposed Final Judgment is to provide the acquirer with everything it needs to effectively compete to provide deepwater PCMS in the Gulf. Where possible, the United States favors the divestiture of an existing business unit that has already demonstrated its ability to compete in the relevant market. In this case, however, neither Defendant has a standalone deepwater PCMS business in the Gulf. Rather, the employees, facilities, and other assets relating to the Defendants' deepwater PCMS operations in the Gulf are deeply intertwined with the Defendants' PCMS operations in other regions and other business lines. To ensure that the acquirer will have all assets necessary to be an effective, long-term competitor, while minimizing disruption to Defendants' broader operations, the proposed Final Judgment assembles a set of assets that will enable the acquirer to effectively preserve competition.
As explained in the
The divestiture package, which is fully described in the proposed Final Judgment, includes, among other things, Champion deepwater chemicals and know-how, a broad right to hire, the tangible and intangible assets Champion currently uses to serve customers in the Gulf, and additional rights and options designed to transfer know-how and customer accounts to the acquirer, which are discussed in more detail below.
The proposed Final Judgment transfers to the acquirer the chemical formulations and know-how that allow Champion to successfully compete for deepwater PCMS opportunities in the Gulf. Going forward, the acquirer will have exclusive rights in the Gulf to provide the chemical formulations that Champion's current customers use and trust, and the know-how needed to apply these formulations effectively to current and future projects.
Defendants use a variety of specially-formulated chemical solutions to provide deepwater PCMS in the Gulf. Although many of the raw chemicals used in these blends are manufactured by third parties, each deepwater PCMS provider in the Gulf has its own unique formulations and know-how relating to the blending and use of these chemicals. These formulations and know-how represent an important qualitative aspect of the deepwater PCMS provided by the Defendants.
Established PCMS providers routinely rely on case histories and past performance data to identify the best chemical formulation for a new project and demonstrate its suitability to prospective customers. New entrants can only offer chemical formulations without a track record of success or wealth of instructive data points. The divestiture package gives the acquirer the ability to offer tried and true chemical formulations, which are expected to reduce customers' aversion to trying a new deepwater PCMS provider.
The proposed Final Judgment provides the acquirer with a patent for Champion's most lucrative production chemical in the Gulf, a low dose hydrate inhibitor critical to many E&P companies' operations in the deepwater Gulf, and exclusive licenses within the deepwater Gulf for all other production chemicals used by Champion in the Gulf.
The proposed Final Judgment provides the acquirer with an expansive right to hire all Champion employees whose job responsibilities relate to the provision of deepwater PCMS in the Gulf. As discussed above, the provision of deepwater PCMS is a service business in which customers place great weight on the expertise, know-how and experience of the individuals working on their accounts. The acquirer's right to hire Champion personnel with deepwater PCMS experience in the Gulf will provide the acquirer with the qualified employees it needs to serve Champion's existing accounts and compete for new projects.
The proposed Final Judgment contains numerous provisions to facilitate the acquirer's ability to hire and retain these employees. The Defendants will provide the acquirer with detailed information about each relevant employee, including his or her responsibilities, job titles, past deepwater PCMS experience in the Gulf, education, training, and salary. The Defendants also will grant the acquirer reasonable access to employees and the ability to interview them. The Defendants are specifically prohibited from interfering with the acquirer's negotiations to hire any relevant employee. For example, if an employee agrees to work for the acquirer, the Defendants must vest such employees' unvested pensions or other equity rights. Importantly, the Defendants must also waive any applicable non-compete or non-disclosure agreement covering information related to the divestiture assets so that the employee may freely provide services to the acquirer and its customers. To allow the acquirer time to develop the business without the risk of Defendants targeting relevant employees to undermine the divestiture, the Defendants are also prohibited for a period of time from soliciting to hire or hiring any relevant employee that is hired by the acquirer.
The proposed Final Judgment grants the acquirer the option to purchase certain facilities and lab equipment that Champion uses in connection with its deepwater PCMS Gulf business. These optional divestiture assets include Champion's Broussard, Louisiana warehouse and distribution facility, which also contains chemical filtration equipment and a quality control laboratory; Champion laboratory
The proposed Final Judgment grants to the acquirer an option to enter into a short-term supply agreement with the Defendants for chemicals licensed or divested to the acquirer. This provision will provide the acquirer with a trusted supply chain while it makes arrangements to produce such chemicals in-house or obtain them from other manufacturers. The supply agreement will assure customers that they will receive the same chemicals from the acquirer that they are currently receiving from Champion.
The proposed Final Judgment does not require divestiture of Defendants' chemical manufacturing plants, which are substantial facilities that support their broader PCMS operations and have significantly more capacity than an acquirer would need to produce production chemicals for the deepwater Gulf.
The proposed Final Judgment contains provisions designed to facilitate the transfer of current customer contracts to provide deepwater PCMS in the Gulf from Champion to the acquirer. In a typical divestiture of a line of business, the ongoing customer contracts usually will transfer with the business unit being divested. Here, there is no line of business being divested and contracts cannot be assigned without customer consent. To encourage customers to transition their business to the acquirer, the proposed Final Judgment contains certain incentives. For example, as discussed above, the acquirer will have the exclusive right to provide the chemicals Champion is currently providing deepwater PCMS customers in the Gulf, and access to the know-how and employees that currently allow Champion to provide deepwater PCMS to customers in the Gulf. As such, the acquirer will be able to step into Champion's shoes and continue to provide ongoing services to customers.
In addition, the proposed Final Judgment requires that the Defendants use their “best efforts” to convince customers to move their business to the acquirer. As a way of assuring customers that such a transition will be smooth, the proposed Final Judgment permits the acquirer to purchase the tangible assets used to provide PCMS to any customer that elects to transition its contract or business to the acquirer. At the option of the acquirer, the Defendants also must provide transitional services sufficient to meet the acquirer's needs for assistance in matters relating to the design, manufacture, formulation, testing, provision, or application of production chemicals for any customer. This provision will allow the acquirer broad access to Champion know-how or expertise related to its provision of deepwater PCMS in the Gulf not ascertainable through its divestiture of case histories and other intangible assets. Deepwater PCMS providers commonly cooperate to prevent operational challenges when a customer chooses a new provider to manage a platform or well. The proposed Final Judgment gives the acquirer the option of requesting additional assistance when taking over Champion's existing accounts.
The proposed Final Judgment requires Defendants to divest to Clariant the divestiture assets within 10 days after the Court signs the Hold Separate Stipulation and Order in this matter. The assets must be divested in such a way as to satisfy the United States, in its sole discretion, that the assets can and will used by the purchaser to compete effectively in the relevant market. Defendants must take all reasonable steps necessary to accomplish the divestiture quickly and must cooperate with the Acquirer.
In the event that Defendants do not accomplish the divestiture within the prescribed periods, the proposed Final Judgment provides that upon application by the United States, the Court will appoint a trustee selected by the United States to effect the divestiture. If a trustee is appointed, the proposed Final Judgment provides that Defendants will pay all of the trustee's costs and expenses. The trustee will have the authority to divest the divestiture assets to an acquirer acceptable to the United States. The trustee's commission will be structured so as to provide an incentive for the trustee based on the price obtained and the speed with which the divestiture is accomplished. After his or her appointment becomes effective, the trustee will file monthly reports with the Court and the United States setting forth his or her efforts to accomplish the divestiture. At the end of six (6) months, if the divestiture has not been accomplished, the trustee will make recommendations to the Court, which shall enter such orders as appropriate, in order to carry out the purpose of the trust, including extending the trust or the term of the trustee's appointment.
Section 4 of the Clayton Act, 15 U.S.C. 15, provides that any person who has been injured as a result of conduct prohibited by the antitrust laws may bring suit in federal court to recover three times the damages the person has suffered, as well as costs and reasonable attorneys' fees. Entry of the proposed Final Judgment will neither impair nor assist the bringing of any private antitrust damage action. Under the provisions of Section 5(a) of the Clayton Act, 15 U.S.C. 16(a), the proposed Final Judgment has no prima facie effect in any subsequent private lawsuit that may be brought against Defendants.
The United States and Defendants have stipulated that the proposed Final Judgment may be entered by the Court after compliance with the provisions of the APPA, provided that the United States has not withdrawn its consent. The APPA conditions entry upon the Court's determination that the proposed Final Judgment is in the public interest.
The APPA provides a period of at least sixty (60) days preceding the
Written comments should be submitted to:
The proposed Final Judgment provides that the Court retains jurisdiction over this action, and the parties may apply to the Court for any order necessary or appropriate for the modification, interpretation, or enforcement of the Final Judgment.
The United States considered, as an alternative to the proposed Final Judgment, a full trial on the merits against the Defendants. The United States could have continued the litigation and sought preliminary and permanent injunctions against Ecolab's acquisition of certain Champion assets. The United States is satisfied, however, that the divestiture of assets described in the proposed Final Judgment will preserve competition for the provision of deepwater PCMS in the Gulf, the relevant market identified by the United States. Thus, the proposed Final Judgment would achieve all or substantially all of the relief the United States would have obtained through litigation, but avoids the time, expense, and uncertainty of a full trial on the merits of the Complaint.
The Clayton Act, as amended by the APPA, requires that proposed consent judgments in antitrust cases brought by the United States be subject to a sixty-day comment period, after which the court shall determine whether entry of the proposed Final Judgment “is in the public interest.” 15 U.S.C. 16(e)(1). In making that determination, the court, in accordance with the statute as amended in 2004, is required to consider:
(A) The competitive impact of such judgment, including termination of alleged violations, provisions for enforcement and modification, duration of relief sought, anticipated effects of alternative remedies actually considered, whether its terms are ambiguous, and any other competitive considerations bearing upon the adequacy of such judgment that the court deems necessary to a determination of whether the consent judgment is in the public interest; and
(B) the impact of entry of such judgment upon competition in the relevant market or markets, upon the public generally and individuals alleging specific injury from the violations set forth in the complaint including consideration of the public benefit, if any, to be derived from a determination of the issues at trial.
15 U.S.C. 16(e)(1)(A) & (B). In considering these statutory factors, the court's inquiry is necessarily a limited one as the government is entitled to “broad discretion to settle with the defendant within the reaches of the public interest.”
As the United States Court of Appeals for the District of Columbia Circuit has held, under the APPA a court considers, among other things, the relationship between the remedy secured and the specific allegations set forth in the government's complaint, whether the decree is sufficiently clear, whether enforcement mechanisms are sufficient, and whether the decree may positively harm third parties.
Courts have greater flexibility in approving proposed consent decrees than in crafting their own decrees following a finding of liability in a litigated matter. “[A] proposed decree must be approved even if it falls short of the remedy the court would impose on its own, as long as it falls within the range of acceptability or is `within the reaches of public interest.'”
Moreover, the court's role under the APPA is limited to reviewing the remedy in relationship to the violations that the United States has alleged in its Complaint, and does not authorize the court to “construct [its] own hypothetical case and then evaluate the decree against that case.”
In its 2004 amendments, Congress made clear its intent to preserve the practical benefits of utilizing consent decrees in antitrust enforcement, adding the unambiguous instruction that “[n]othing in this section shall be construed to require the court to conduct an evidentiary hearing or to require the court to permit anyone to intervene.” 15 U.S.C. 16(e)(2). The language wrote into the statute what Congress intended when it enacted the Tunney Act in 1974, as Senator Tunney explained: “[t]he court is nowhere compelled to go to trial or to engage in extended proceedings which might have the effect of vitiating the benefits of prompt and less costly settlement through the consent decree process.” 119 Cong. Rec. 24,598 (1973) (statement of Senator Tunney). Rather, the procedure for the public interest determination is left to the discretion of the court, with the recognition that the court's “scope of review remains sharply proscribed by precedent and the nature of Tunney Act proceedings.”
There are no determinative materials or documents within the meaning of the APPA that were considered by the United States in formulating the proposed Final Judgment.
Dated: April 8, 2013.
Respectfully submitted,
I hereby certify that on April 8, 2013, I caused a copy of the foregoing Competitive Impact Statement, Complaint, proposed Final Judgment, Hold Separate Stipulation and Order, and Plaintiff United States' Explanation of Procedures for Entry of the Final Judgment to be served on counsel for defendants in this matter in the manner set forth below:
By electronic mail:
This Court has jurisdiction over the subject matter of and each of the parties to this action. The Complaint states a
As used in this Final Judgment:
A. “Acquirer” means Clariant, the entity to which Defendants shall divest the Divestiture Assets.
B. “AKA” means a Production Chemical that has an identical formulation or chemical makeup as a Champion Deepwater Production Chemical but has a different SKU or product name.
C. “Call-off Agreement” means an agreement to provide production chemical management services for a particular asset, geographic region, or time period for a customer with whom the supplier has a Master Service Agreement in place.
D. “Broussard Facility” means Champion's facility and other assets located at 304 Ida Rd., Broussard, Louisiana 70518.
E. “Champion” means Champion Technologies, Inc., a Texas corporation with its headquarters in Houston, Texas, its successors, assigns, subsidiaries, divisions, groups, affiliates, partnerships, and joint ventures, and their directors, officers, managers, agents, and employees.
F. “Champion Deepwater Gulf PCMS Customer” means any entity to which Champion provided PCMS in the Deepwater Gulf at any time between January 1, 2011 and the date the divestitures contemplated by this Final Judgment are completed.
G. “Champion Deepwater Gulf Production Chemical” means any Production Chemical used to treat an oil or gas producing well in the Deepwater Gulf, including, but not limited to, HI43 and those chemicals listed in Schedule A, and all related tangible and intangible assets.
H. “Clariant” means Clariant Corporation, the legal U.S. affiliate of Clariant International Ltd., headquartered in Charlotte, North Carolina, its successors, assigns, subsidiaries, divisions, groups, affiliates, partnerships, and joint ventures, and their directors, officers, managers, agents, and employees.
I. “Customer-Facing Relevant Employee” means any employee who visits a Champion Deepwater Customer's Deepwater Gulf well or platform to provide PCMS, Relevant Employees who do not visit the Deepwater Gulf well or platform but directly supervise employees who do, or Relevant Employees who regularly interact with Champion Deepwater Gulf Customers but do not visit the customer's Deepwater Gulf wells or platforms on a regular basis.
J. “Deepwater Gulf” means the areas of the United States Gulf of Mexico that have water depths exceeding 1,000 feet.
K. “Deepwater Gulf Well or Platform” means a well, cluster of wells, or production facility associated with a well found in the Deepwater Gulf.
L. “Divestiture Assets” means:
(1) HI43 and all related Intellectual Property Rights;
(2) Exclusive, perpetual, paid-up, non-transferable licenses for use in the Deepwater Gulf to all Intellectual Property Rights related to Champion's provision of Deepwater Gulf PCMS and Champion Deepwater Gulf Production Chemicals that Champion has provided to a Deepwater Gulf PCMS Customer since January 1, 2012 for use in the Deepwater Gulf and any AKAs of such products. Such licenses will not be subject to any requirement to grant back to the Defendants any improvements or modifications made to these assets;
(3) All Intangible Assets, excluding Intellectual Property Rights, related to Champion's provision of Deepwater Gulf PCMS;
(4) The option to acquire the Broussard Facility and all tangible and intangible assets used by or located at the Broussard Facility that are used to design, develop, manufacture, market, service, package, filter, blend, distribute, or test Deepwater Gulf Production Chemicals or provide PCMS to Champion Deepwater Gulf PCMS Customers;
(5) The option to acquire the Deepwater Gulf Production Chemical Equipment listed in Schedule B, delivered to the Broussard Facility or to a U.S. location specified by the Acquirer; and
(6) For each Champion Deepwater PCMS Customer who elects to transition its contract or business to the Acquirer, the option to acquire the tangible assets maintained by Champion for the purpose of providing PCMS at that Deepwater Gulf PCMS Customer's Deepwater Gulf Well(s) or Platform(s).
M. “Ecolab” means Ecolab Inc., a Delaware corporation with its headquarters in St. Paul, MN, its successors and assigns, and its subsidiaries, divisions, groups, affiliates, partnerships, and joint ventures, and their directors, officers, managers, agents, and employees.
N. “Gulf” means the United States Gulf of Mexico.
O. “HI43” means Champion's low dose hydrate inhibitor Production Chemical claimed in U.S. Patent No. 7,381,689 and any reissue (and any foreign counterparts).
P. “Intangible Assets” means:
(1) know-how, including, but not limited to, recipes, formulas, machine settings, drawings, blueprints, designs, design protocols, standards, design tools, simulation capability, specifications, and application, manufacturing, blending, filtration, and testing techniques or processes;
(2) confidential information or any information that provides an advantage with respect to competitors by virtue of not being known by those competitors, including strategic information, business plans, contract terms, pricing, processes and compilations of information, information concerning customers or vendors, including vendor and customer lists, sales materials, and information regarding methods of doing business.
(3) data concerning historic and current research and development, including but not limited to, designs of experiments, and the results of unsuccessful designs and experiments;
(4) computer software, databases (
(5) contractual rights, to the extent they are assignable;
(6) all authorizations, permits, licenses, registrations, or other forms of permission, consent, or authority issued, granted, or otherwise made available by or under the authority of any governmental authority; and
(7) Intellectual Property Rights.
Q. “Intellectual Property Rights” means information, designs, creations, inventions, and other intangible property for which exclusive rights are recognized, including but not limited to, patents or patent applications, licenses and sublicenses, copyrights, trademarks, trade secrets, trade names, service marks, and service names.
R. “The License-Back Period” means the six (6) month period following Defendants' completion of the divestitures required by this Final Judgment, during which the Defendants are granted a license to use Champion Deepwater Gulf Production Chemicals with Intellectual Property Rights that have been transferred or licensed to the Acquirer.
S. “Permian” means Permian Mud Service, Inc., a Texas corporation with its headquarters in Houston, Texas, its successors and assigns, and its subsidiaries (including Champion Technologies, Inc.), divisions, groups, affiliates, partnerships, and joint ventures, and their directors, officers, managers, agents, and employees.
T. “Production Chemicals” means the blends of chemical intermediates and solvents that are introduced to the wellbore, topside equipment, umbilicals, flowlines or other well infrastructure of an oil or gas well to facilitate the production or flow of hydrocarbons from the wellbore to the topside equipment, protect the well's infrastructure and equipment, remove hazardous or undesirable elements from the hydrocarbons or produced water, and facilitate the separation of oil, gas, and water in the topside equipment.
U. “PCMS” means the provision of production chemical management services, including but not limited to product selection or design, front-end engineering design assistance, manufacture or blending of production chemicals, application of chemicals, or monitoring and testing of well conditions and product efficacy.
V. “Relevant Employees” means all Champion employees whose job responsibilities at any time between January 1, 2012 and the closing of the Transaction related to the provision of Deepwater Gulf PCMS.
W. “Transaction” means Ecolab's acquisition of Permian described in the “Agreement and Plan of Merger” between Ecolab, Permian, OFC Technologies Corp., and John W. Johnson, Steven J. Lindley, and J. Loren Ross, solely in their capacity as the Representatives, dated October 11, 2012, as amended.
X. “Tangible Asset” means any physical asset (excluding real property), including but not limited to:
(1) all machinery, equipment, hardware, spare parts, tools, fixtures, business machines, computer hardware, other information technology assets, furniture, laboratories, supplies, and materials, including but not limited to testing equipment, injection equipment, monitoring equipment, and storage vessels;
(2) improvements, fixed assets, and fixtures pertaining to the real property identified as a Divestiture Asset;
(3) all inventories, raw materials, work-in-process, finished goods, supplies, stock, parts, packaging materials and other accessories related thereto; and
(4) business records including financial records, accounting and credit records, tax records, governmental licenses and permits, bid records, customer lists, customer contracts, supplier contracts, service agreements; operations records including vessel logs, treatment logs, calendars, and schedules; job records, research and development records, health, environment and safety records, repair and performance records, training records, and all manuals and technical information Defendants provide to their own employees, customers, suppliers, agents or licensees.
This Final Judgment applies to Defendants Ecolab and Permian, as defined above, and all other persons in active concert or participation with any of them who receive actual notice of this Final Judgment by personal service or otherwise.
A. Defendants are ordered and directed, within ten (10) calendar days after the Court signs the Hold Separate Stipulation and Order in this matter, to divest the Divestiture Assets to the Acquirer in a manner consistent with this Final Judgment. Defendants shall use their best efforts to accomplish the divestitures ordered by this Final Judgment as expeditiously as possible. The United States, in its sole discretion, may extend the time period for any divestiture for an additional period of time not to exceed sixty (60) days.
B. Defendants shall offer to furnish to the Acquirer, subject to customary confidentiality assurances, all information and documents relating to the Divestiture Assets customarily provided in a due diligence process except such information or documents subject to the attorney-client privileges or work-product doctrine. Defendants shall make available such information to the United States at the same time that such information is made available to the Acquirer. Any questions that arise during the due diligence process concerning whether particular assets are appropriately considered Divestiture Assets subject to this Final Judgment shall be resolved by the United States, in its sole discretion, consistent with the terms of this Final Judgment.
C. Defendants shall permit the Acquirer of the Divestiture Assets to have reasonable access to personnel and to make inspections of the physical facilities of the Divestiture Assets; access to any and all environmental, zoning, and other permit documents and information; and access to any and all financial, operational, or other documents and information customarily provided as part of a due diligence process.
D. Defendants shall warrant to the Acquirer that each asset will be operational on the date of sale. Defendants shall maintain and enforce all intellectual property rights licensed to the Acquirer and maintain and protect all trade secrets and confidential information furnished to the Acquirer pursuant to the proposed Final Judgment.
E. Defendants shall not take any action that will impede in any way the permitting, operation, use, or divestiture of the Divestiture Assets.
F. Defendants shall warrant to the Acquirer that there are no material defects in the environmental, zoning or other permits pertaining to the operation of each asset, and that following the sale of the Divestiture Assets, Defendants will not undertake, directly or indirectly, any challenges to the environmental, zoning, or other permits relating to the operation of the Divestiture Assets.
G. At the option of the Acquirer, the Defendants shall enter into a supply agreement, toll manufacturing, or toll blending agreement with the Acquirer to manufacture, blend or supply, any Champion Deepwater Gulf Production Chemical or component(s) thereof for a period of up to one (1) year, which may be extended by the United States, in its sole discretion, for an additional period of time not to exceed one (1) year. The Defendants shall manufacture and blend the Champion Deepwater Gulf Production Chemicals or chemical intermediates using the manufacturing, blending and quality assurance procedures used by Champion directly preceding the Divestiture unless the Acquirer authorizes a change. The Defendants shall also procure the raw materials or intermediates used to make the Champion Deepwater Gulf Production Chemicals from the same source used by Champion directly preceding the Divestiture unless the Acquirer authorizes a change. For each year of the tolling agreement, the Defendants shall supply up to 120% of the volume of Champion Deepwater Gulf Production Chemicals sold in the Deepwater Gulf in the prior year. The terms and conditions of such agreement shall be commercially reasonable and shall be subject to the approval of the United States, in its sole discretion.
H. At the option of the Defendants, the Acquirer shall enter into an agreement to provide the Defendants with:
(1) Non-exclusive, non-transferable fully paid-up licenses to provide any Champion Deepwater Production Chemical to Champion Deepwater Gulf PCMS Customers, for use in the Deepwater Gulf during the License-Back Period. Such licenses will be for the sole purpose of enabling the Defendants to continue providing those chemicals to a Champion Deepwater Gulf Customer during the License-Back Period. The United States, in its sole discretion, may
(2) A perpetual, non-exclusive, non-transferable, fully paid-up license to make, have made, use, or sell HI43 outside the Deepwater Gulf. The terms and conditions of any contractual arrangement intended to satisfy this provision must be reasonably related to market conditions for such licenses. Such license may, at the Acquirer's discretion, require the Defendants to grant back to the Acquirer any modifications or improvements made by the Defendants to HI43.
I. The Defendants shall use their best efforts to assign, subcontract, or otherwise transfer to the Acquirer any (i) contract to provide PCMS in the Deepwater Gulf, or (ii) portion of a Master Service Agreement or global agreement, including Call-off Agreements, between Champion and a Champion Deepwater Gulf PCMS Customer relating to the provision of Champion Deepwater Gulf PCMS in the Deepwater Gulf. To this end, the Defendants shall notify each Champion Deepwater Gulf PCMS Customer of the terms of this Final Judgment; release the Champion Deepwater Gulf PCMS Customer of any notice requirements or obligations that require the customer to use Champion's services or refrain from using another supplier's services with respect to any Deepwater Gulf assets; introduce the Acquirer to each Customer, request each Customer's consent to assign that Customer's contract to the Acquirer; and specifically inform each such Customer that the Defendants' rights to the divested Champion Deepwater Gulf Production Chemicals, in Deepwater Gulf, expire after six (6) months. The Defendants shall not encourage any Champion Deepwater Gulf Customer to request an extension of the License-Back Period.
J. At the option of the Acquirer, Defendants shall enter into a transition services agreement with that Acquirer sufficient to meet the Acquirer's needs for assistance in matters relating to the design, manufacture, formulation, testing, provision, or application of Production Chemicals and related services to any Champion Deepwater Gulf Customer for a period of up to three (3) months. The Acquirer may exercise this option during the License-Back Period and for three (3) months thereafter. The Defendant must make the personnel providing the transition services available during normal business hours. The terms and conditions of any contractual arrangement intended to satisfy this provision must be reasonably related to the market value of the expertise of the personnel providing any needed assistance.
K. For a period of two (2) years following completion of the divestitures required by this Final Judgment, Defendants shall not, directly or indirectly, assign any Customer-Facing Relevant Employee to provide PCMS in the Deepwater Gulf to a Champion Deepwater Gulf PCMS Customer at a Deepwater Gulf Well or Platform for which the employee provided PCMS, directly or indirectly, while employed by Champion, except in connection with services provided to a Champion Deepwater Gulf PCMS Customer during the applicable License-Back Period for that customer.
L. Unless the United States otherwise consents in writing, the divestiture pursuant to Section IV, or by trustee appointed pursuant to Section VI, of this Final Judgment, shall include the entire Divestiture Assets, and shall be accomplished in such a way as to satisfy the United States, in its sole discretion, that the Divestiture Assets can and will be used by the Acquirer as part of a viable, ongoing business engaged in the provision of PCMS for oil and gas wells located in the Deepwater Gulf, and that such divestiture will remedy the competitive harm alleged in the Complaint. The divestiture, whether pursuant to Section IV or Section VI of this Final Judgment,
(1) shall be made to an acquirer that, in the United States' sole judgment, has the intent and capability (including the necessary managerial, operational, technical and financial capability) of competing effectively in the business of providing PCMS for oil and gas wells in the Deepwater Gulf; and
(2) shall be accomplished so as to satisfy the United States, in its sole discretion, that none of the terms of any agreement between an acquirer and Defendants give Defendants the ability unreasonably to raise the acquirer's costs, to lower the acquirer's efficiency, or otherwise to interfere in the ability of the acquirer to compete effectively.
A. The Acquirer shall have the right to hire Relevant Employees while the License-Back Period is in effect with respect to any Champion Deepwater Gulf PCMS Customer. To enable the Acquirer to make offers of employment, Defendants shall provide the Acquirer and the United States with organization charts and information relating to Relevant Employees, including name, job title, past experience relating to development, production, sale or administration of Production Chemicals for use in oil or gas wells in the Deepwater Gulf, responsibilities, training and educational history, relevant certifications, and, to the extent permissible by law, job performance evaluations, and current salary and benefits information.
B. Upon request, Defendants shall make the Relevant Employees available for interviews with the Acquirer during normal business hours at a mutually agreeable location and will not interfere with any negotiations by the Acquirer to employ the Relevant Employees. Interference with respect to this paragraph includes, but is not limited to, offering to increase the salary or benefits of Relevant Employees other than as a part of a company-wide increase in salary or benefits granted in the ordinary course of business.
C. For Relevant Employees who elect employment by the Acquirer, Defendants shall waive all non-compete agreements and all nondisclosure agreements, except as specified below, vest all unvested pension and other equity rights, and provide all benefits to which the Relevant Employees would generally be provided if transferred to a buyer of an ongoing business. For a period of twelve (12) months after the Acquirer's right to hire expires, the Defendants shall not solicit to hire, or hire, any Relevant Employee hired by the Acquirer, unless (1) such individual is terminated or laid off by the Acquirer or (2) the Acquirer agrees in writing that Defendants may solicit or hire that individual.
D. Nothing in this Section shall prohibit Defendants from maintaining any reasonable restrictions on the disclosure by an employee who accepts an offer of employment with the Acquirer of the Defendants' proprietary non-public information that is (1) not otherwise required to be disclosed by this Final Judgment and (2) unrelated to the Divestiture Assets.
A. If the Defendants have not divested the Divestiture Assets within the time
B. After the appointment of a trustee becomes effective, only the trustee shall have the right to sell the Divestiture Assets. The trustee shall have the power and authority to accomplish the divestitures to acquirers acceptable to the United States at such price and on such terms as are then obtainable upon reasonable effort by the trustee, subject to the provisions of Sections IV, V, and VI of this Final Judgment, and shall have such other powers as this Court deems appropriate. Subject to Section VI(D) of this Final Judgment, the trustee may hire at the cost and expense of the Defendants any investment bankers, attorneys, or other agents, who shall be solely accountable to the trustee, reasonably necessary in the trustee's judgment to assist in the divestitures.
C. Defendants shall not object to sales by the trustee on any ground other than the trustee's malfeasance. Any such objections by Defendants must be conveyed in writing to the United States and the trustee within ten calendar days after the trustee has provided the notice required under Section VII.
D. The trustee shall serve at the cost and expense of Defendants, on such terms and conditions as the United States approves, and shall account for all monies derived from the sale of the assets sold by the trustee and all costs and expenses so incurred. After approval by the Court of the trustee's accounting, including fees for its services and those of any professionals and agents retained by the trustee, all remaining money shall be paid to Defendants and the trust shall then be terminated. The compensation of the trustee and any professionals and agents retained by the trustee shall be reasonable in light of the value of the Divestiture and based on a fee arrangement providing the trustee with an incentive based on the price and terms of the divestitures and the speed with which it is accomplished, but timeliness is paramount.
E. Defendants shall use their best efforts to assist the trustee in accomplishing the required divestitures. The Defendants' failure to comply with Section IV(A) does not relieve the Defendants of their obligations to comply with the remainder of the terms in this Final Judgment. If a trustee is appointed, the acquirer procured by the trustee shall be deemed the Acquirer referenced in this Final Judgment. The trustee and any consultants, accountants, attorneys, and other persons retained by the trustee shall have full and complete access to the personnel, books, records, and facilities of the business to be divested, and Defendants shall develop financial and other information relevant to such business as the trustee may reasonably request, subject to reasonable protection for trade secret or other confidential research, development, or commercial information. Defendants shall take no action to interfere with or to impede the trustee's accomplishment of the divestitures.
F. After its appointment, the trustee shall file monthly reports with the United States and the Court setting forth the trustee's efforts to accomplish the divestitures ordered under this Final Judgment. To the extent such reports contain information that the trustee deems confidential, such reports shall not be filed in the public docket of the Court. Such reports shall include the name, address, and telephone number of each person who, during the preceding month, made an offer to acquire, expressed an interest in acquiring, entered into negotiations to acquire, or was contacted or made an inquiry about acquiring, any interest in the Divestiture Assets, and shall describe in detail each contact with any such person. The trustee shall maintain full records of all efforts made to divest the Divestiture Assets.
G. If the trustee has not accomplished the divestitures ordered under this Final Judgment within six (6) months after its appointment, the trustee shall promptly file with the Court a report setting forth: (i) The trustee's efforts to accomplish the required divestitures; (ii) the reasons, in the trustee's judgment, why the required divestitures have not been accomplished; and (iii) the trustee's recommendations. To the extent such reports contain information that the trustee deems confidential, such reports shall not be filed in the public docket of the Court. The trustee shall at the same time furnish such report to the United States, which shall have the right to make additional recommendations consistent with the purpose of the trust. The Court thereafter shall enter such orders as it shall deem appropriate to carry out the purpose of the Final Judgment, which may, if necessary, include extending the trust and the term of the trustee's appointment by a period requested by the United States.
A. Within two (2) business days following execution of a definitive contract for sale of any of the Divestiture Assets, Defendants or the trustee, whichever is then responsible for effecting the divestiture required herein, shall notify the United States of any proposed divestiture required by Sections IV or VI of this Final Judgment, and submit to the United States a copy of the proposed contract for sale and any other agreements with the Acquirer relating to the Divestiture Assets. If the trustee is responsible, it shall similarly notify Defendants. The notice shall set forth the details of the proposed divestiture and list the name, address, and telephone number of each person not previously identified who offered or expressed an interest in or desire to acquire any ownership interest in the Divestiture Assets, together with full details of the same.
B. Within fifteen (15) calendar days of receipt by the United States of such notice, the United States may request from Defendants, the proposed Acquirer, any other third party, or the trustee, if applicable, additional information concerning the proposed divestiture, the proposed Acquirer, and any other potential Acquirers. Defendants and the trustee shall furnish any additional information requested within fifteen (15) calendar days of the receipt of the request, unless the parties shall otherwise agree.
C. Within thirty (30) calendar days after receipt of the notice or within twenty (20) calendar days after the United States has been provided the additional information requested from Defendants, the proposed Acquirer, any third party, and the trustee, whichever is later, the United States shall provide written notice to Defendants and the trustee, if there is one, stating whether or not it objects to the proposed divestiture, provided, however, that the United States may extend the period for its review up to an additional thirty (30) calendar days. If the United States provides written notice that it does not object, the divestiture may be consummated, subject only to Defendants' limited right to object to the sale under Section VI(C) of this Final Judgment. Absent written notice that the United States does not object to the proposed Acquirer or upon objection by the United States, a divestiture proposed under Section IV or Section V shall not be consummated. Upon objection by Defendants under Section V(C), a divestiture proposed under Section V shall not be consummated unless approved by the Court.
Defendants shall not finance all or any part of any purchase made pursuant to Section IV or VI of this Final Judgment.
Until the divestitures required by this Final Judgment have been accomplished, Defendants shall take all steps necessary to comply with the Hold Separate Stipulation and Order entered by the Court. Defendants shall take no action that would jeopardize the divestiture ordered by the Court.
A. Within fifteen (15) calendar days after the Court signs the Hold Separate Stipulation and Order in this matter, and every thirty (30) calendar days thereafter until the divestiture has been completed under Section IV or VI, Defendants shall deliver to the United States an affidavit as to the fact and manner of its compliance with Sections IV or VI of this Final Judgment. Each such affidavit shall include the name, address, and telephone number of each person who, during the preceding thirty (30) calendar days, made an offer to acquire, expressed an interest in acquiring, entered into negotiations to acquire, or was contacted or made an inquiry about acquiring, any interest in the Divestiture Assets, and shall describe in detail each contact with any such person during that period. Each such affidavit shall also include a description of the efforts Defendants have taken to solicit buyers for the Divestiture Assets and to provide required information to prospective Acquirers, including the limitations, if any, on such information. Assuming the information set forth in the affidavit is true and complete, any objection by the United States to information provided by Defendants, including limitation on information, shall be made within fourteen (14) calendar days of receipt of such affidavit.
B. Within twenty (20) calendar days of the filing of the Complaint in this matter, Defendants shall deliver to the United States an affidavit that describes in reasonable detail all actions Defendants have taken and all steps Defendants have implemented on an ongoing basis to comply with Section IX of this Final Judgment. Defendants shall deliver to the United States an affidavit describing any changes to the efforts and actions outlined in Defendants' earlier affidavits filed pursuant to this section within fifteen (15) calendar days after the change is implemented.
C. Defendants shall keep all records of all efforts made to preserve and divest the Divestiture Assets until one year after such divestiture has been completed.
A. For the purposes of determining or securing compliance with this Final Judgment, or of any related orders such as any Hold Separate Stipulation and Order, or of determining whether the Final Judgment should be modified or vacated, and subject to any legally recognized privilege, from time to time duly authorized representatives of the United States Department of Justice Antitrust Division, including consultants and other persons retained by the United States, shall, upon written request of an authorized representative of the Assistant Attorney General in charge of the Antitrust Division, and on reasonable notice to Defendants, be permitted:
(1) Access during Defendants' office hours to inspect and copy, or at the option of the United States, to require Defendants to provide hard copy or electronic copies of, all books, ledgers, accounts, records, data, and documents in the possession, custody, or control of Defendants, relating to any matters contained in this Final Judgment; and
(2) To interview, either informally or on the record, Defendants' officers, employees, or agents, who may have their individual counsel present, regarding such matters. The interviews shall be subject to the reasonable convenience of the interviewee and without restraint or interference by Defendants.
B. Upon the written request of an authorized representative of the Assistant Attorney General in charge of the Antitrust Division, Defendants shall submit written reports or responses to written interrogatories, under oath if requested, relating to any of the matters contained in this Final Judgment as may be requested.
C. No information or documents obtained by the means provided in this Section shall be divulged by the United States to any person other than an authorized representative of the executive branch of the United States, except in the course of legal proceedings to which the United States is a party (including grand jury proceedings), or for the purpose of securing compliance with this Final Judgment, or as otherwise required by law.
D. If at the time information or documents are furnished by Defendants to the United States, Defendants represent and identify in writing the material in any such information or documents to which a claim of protection may be asserted under Rule 26(c)(1)(G) of the Federal Rules of Civil Procedure, and Defendants mark each pertinent page of such material, “Subject to claim of protection under Rule 26(c)(1)(G) of the Federal Rules of Civil Procedure,” then the United States shall give Defendants ten (10) calendar days notice prior to divulging such material in any legal proceeding (other than a grand jury proceeding).
Defendants may not reacquire any of the Divestiture Assets during the term of this Final Judgment.
This Court retains jurisdiction to enable any party to this Final Judgment to apply to the Court at any time for further orders and directions as may be necessary or appropriate to carry out or construe this Final Judgment, to modify any of its provisions, to enforce compliance, and to punish violations of its provisions.
Unless the Court grants an extension, this Final Judgment shall expire ten (10) years from the date of its entry.
The parties have complied with the requirements of the Antitrust Procedures and Penalties Act, 15 U.S.C. 16, including making copies available to the public of this Final Judgment, the Competitive Impact Statement, and any comments thereon and the United States' responses to comments. Based upon the record before the Court, which includes the Competitive Impact Statement and any comments and response to comments filed with the Court, entry of this Final Judgment is in the public interest.
United States District Judge
I, Isaac Fulwood, of the United States Parole Commission, was present at a meeting of said Commission, which started at approximately 11:00 a.m., on Tuesday, February 12, 2013, at the U.S. Parole Commission, 90 K Street NE., Third Floor, Washington, DC 20530. The purpose of the meeting was to discuss original jurisdiction cases pursuant to 28 CFR 2.27. Five Commissioners were present, constituting a quorum when the vote to close the meeting was submitted.
Public announcement further describing the subject matter of the meeting and certifications of the General Counsel that this meeting may be closed by votes of the Commissioners present
Mine Safety and Health Administration, Labor.
Notice.
Section 101(c) of the Federal Mine Safety and Health Act of 1977 and 30 CFR part 44 govern the application, processing, and disposition of petitions for modification. This notice is a summary of petitions for modification submitted to the Mine Safety and Health Administration (MSHA) by the parties listed below to modify the application of existing mandatory safety standards codified in Title 30 of the Code of Federal Regulations.
All comments on the petitions must be received by the Office of Standards, Regulations and Variances on or before May 20, 2013.
You may submit your comments, identified by “docket number” on the subject line, by any of the following methods:
1.
2.
3.
MSHA will consider only comments postmarked by the U.S. Postal Service or proof of delivery from another delivery service such as UPS or Federal Express on or before the deadline for comments.
Barbara Barron, Office of Standards, Regulations and Variances at 202–693–9447 (Voice),
Section 101(c) of the Federal Mine Safety and Health Act of 1977 (Mine Act) allows the mine operator or representative of miners to file a petition to modify the application of any mandatory safety standard to a coal or other mine if the Secretary of Labor determines that:
1. An alternative method of achieving the result of such standard exists which will at all times guarantee no less than the same measure of protection afforded the miners of such mine by such standard; or
2. That the application of such standard to such mine will result in a diminution of safety to the miners in such mine.
In addition, the regulations at 30 CFR 44.10 and 44.11 establish the requirements and procedures for filing petitions for modification.
(1) The slope belt conveyor will be equipped with a backup generator to supply power to the slope belt in the event of power outage.
(2) The slope belt conveyor will be equipped with an automatic braking system to prevent the belt from reversing direction if power is lost.
(3) Positive acting stop controls will be installed along the slope belt conveyor and the controls will be readily accessible and maintained so that the belt can be stopped or started at any location.
(4) The slope belt conveyor will have a minimum vertical clearance of 18 inches from the nearest overhead projection when measured from the edge of the belt, and there will be at least 36-inches of side clearance where persons board and leave the slope conveyor.
(5) When persons are being transported on the slope belt conveyor, whether on regularly scheduled mantrips or as an emergency escape facility, the belt speed will not exceed 300 feet per minute when the vertical clearance is less than 24 inches and will not exceed 350 feet per minute when the vertical clearance is 24 inches or more.
(6) Adequate illumination including colored lights or reflectors will be installed at all loading and unloading stations on the slope conveyor belt. Such colored lights will be located as to be observable to all persons riding the conveyor belt.
(7) The slope conveyor belt will not be used to transport supplies and the slope conveyor will be clear of all material, including coal, before persons are transported.
(8) Telephone or other suitable communications will be provided at points where persons are loaded on or unloaded from the slope belt conveyor.
(9) Crossing facilities will be provided wherever persons must cross the moving slope conveyor or any other moving belt conveyor belt to gain access to or leave the mechanical escape facility.
(10) An operator will be stationed to turn the belt on and off.
(11) The slope belt conveyor will be examined by a certified person(s) at least once each week. The examination will include
(a) Operating the slope belt conveyor as an emergency escape facility.
(b) Examination for hazards along the slope belt conveyor and examination of the mechanical and electrical condition of the slope conveyor system.
(c) Immediate reporting of any hazards or mechanical deficiencies observed.
(d) Confirmation that any reported hazards or defects are corrected before the slope belt is used as a mantrip or serves as an emergency escapeway facility.
(12) The person(s) making the examination(s) required by the Proposed Decision and Order (PDO) will certify by initials, date and time the examination(s) was made. The certification will be at the loading and
(13) Prior to implementing the modification requested in this petition, all persons who inspect, maintain, or ride the slope conveyor will be instructed in the special terms and conditions of this alternative method.
The petitioner asserts that the proposed alternative method will guarantee the miners affected no less than the same measure of protection afforded by the standard.
(1) The Lower Kittanning coal seam at Heilwood Mine is 26 to 54 inches high. Variations in coal height often are associated with the presence of sandstone channels which scour the coalbed and also contribute to irregular structure contours (i.e., seam rolls).
(2) The equipment consists of three Joy Shuttle Cars, Model #21SC.
(3) Due to widely varying seam heights, the shuttle car canopies often have to be lowered to their minimum height. In this lowered position, the forward window height varies from 6 to 8 inches among the three cars. The lowered canopy position greatly reduces visibility and line-of-sight for the equipment operator's which, in turn, increases the potential for “struck by” injuries to miners traveling or working in the vicinity of the equipment.
(4) Concern for “struck by” accidents is exacerbated by the fact that the cars are operating in narrow entries with less than normal clearances. The approved roof control plan limits entry width to a maximum of 18 feet and the entries actually are being maintained at about 16 feet to limit roof span and improve entry stability.
(5) The lowered canopy position creates cramped and physically stressful conditions for the equipment operators.
(6) To alleviate the cramped posture and limited visibility associated with the lowered canopy position, miners may be tempted to lean out of the side of the operator's compartment, which negates any benefit of the canopy and increases the potential for head/neck injuries.
(7) The mine roof at the Heilwood Mine varies substantially but currently, shuttle cars are operating in a section in which tensioned bolts, cable bolts, and roof channels are specified in the approved roof plan to be installed to ensure the stability of thinly laminated strata and/or interbedded sandstone and shale layers. The primary supports (fully grouted tensioned rebar bolts), supplemental supports (tensioned and non-tensioned cable bolts), and roof channels used to address these conditions protrude below the roof line and are more vulnerable to damage by moving equipment than traditional headed roof bolts.
(8) Mining heights on the section currently vary from 45 to 51 inches. However, measurements beneath the installed support measure as little as 41 inches. Much of the height reduction is associated with the bolt/cable/plate dimension below the roof line. Some loss of height is also due to floor heave. Despite the use of adequately sized pillars (safety factor approximately equal to 3.5), floor heave is sometimes evident on the mining section.
(9) The shuttle cars have been equipped with the lowest profile tire that can be practically employed (35x10x15). With these tires and the canopies in the lowest possible position, the shuttle car canopies extend 41 inches above the mine floor. Uneven bottom profiles (i.e., rolling seam conditions) and/or seam height variations in the mine cause the canopies to strike and dislodge roof bolts resulting in a damaged and weakened roof support system.
(10) Shuttle car operators will remain under supported roof at all times. Canopies will be used in areas where the mining height exceeds forty-eight (48) inches.
The petitioner asserts that the use of canopies on shuttle cars in mining heights less than forty eight inches in the Heilwood Mine results in a diminution of safety to the miners.
(1) As an alternative method of providing a waterline due to the freezing and subfreezing conditions experienced at the Highland No. 9 Mine site during cold weather, the petitioner proposes to establish, by designation, a dry waterline in the slope area of the mine to prevent water contained in the otherwise charged waterline from freezing, that could prevent water from flowing through the waterline during an emergency, or, by expansion, could damage the waterline and connected firefighting equipment.
(2) The area to be serviced by the dry waterline system is from the surface mouth of the slope to the slope bottom. Areas of the mine inby the designated terminus of the dry waterline system at the slope bottom will continue to be serviced by a charged waterline as currently installed and maintained.
(3) As an alternative to the waterline in the slope remaining charged at all times, the petitioner proposes to install a 2-inch dry-line the full length of the slope belt. Fire house outlets will be installed and maintained at each access door between the upper and lower levels of the slope not to exceed 300 feet. A water outlet will be installed and maintained coming from the steel main water supply at the belt tailpiece. All access doors between the upper and lower compartments will be maintained in working condition.
(4) The dry-line system will only be used October 1st through April 30th. During the remaining days of the year, the water line along the slope belt conveyor will remain charged with water. Before entering the mine, miners will be informed when the system is changed from normal to dry line and when it is changed back.
(5) Two electronically actuated solenoid valves installed in parallel will be in-line with the slope belt waterline located in an underground concrete hole located on the surface. Electrical power will be necessary to hold these valves in a closed position. The valves will return to the open position (charging the waterline) upon loss of voltage or when activated by computer.
(6) The solenoids valves will be connected to the carbon monoxide monitoring system through programmable logic controller (PLC) programming. The valves will be automatically activated if any carbon monoxide (CO) sensor along the slope,
(7) A manually operated bypass valve will be installed in parallel with the automatic valves. The manually operated valve will normally be closed and utilized to charge the waterline should both automatic valves fail. If a miner or miners are underground, a person trained in the location and operation of the manual bypass valve will be sent immediately to the valve if the CO at any slope sensor or the sensor inby the slope tailpiece reaches 5 parts per million above the ambient level of CO specified in the mine approved ventilation plan. If the automatic valves fail to open and charge the waterline at 10 parts per million CO above the ambient level of CO specified in the mine approved ventilation plan, then the person will open the manual bypass valve to charge the waterline.
(8) Water will automatically charge the line if either the solenoid or manual bypass is moved to the open position.
(9) The solenoid valves will be capable of being actuated and reset from the CO monitoring room. At least two miners on each shift and the Security Station staff will be trained in procedures for actuation and resetting the solenoid valves. A properly trained person will be available at all times (i.e., 24 hours each day, 7 days each week) to actuate and/or reset the valves.
(10) An outlet with a manual valve will be installed downstream of the solenoid valves just outside the underground concrete hole. This manual valve will be designated as a test/drain valve and will be closed except when testing the system or draining the water after testing or actuation.
(11) A manual valve will be installed just downstream of the test/drain valve. This valve will be open at all times, except when testing the system. During testing, this valve may be closed to isolate the dry-line, allowing the system to be tested without filling the entire length of the waterline.
(12) All valves and switches that are part of this system will be maintained operable and will be clearly marked and labeled in a conspicuous and reflective manner. All valves and switches will be located so that they are easily accessible for inspection and operation. Reflective signs will be conspicuously placed in the slope belt compartment indicating the location of each fire hose outlet.
(13) The dry-line system will be examined and functionally tested at intervals not to exceed 7 days. A record of the examinations will be recorded according to 30 CFR 75.364(h). Any deficiency will be corrected immediately and noted along with the corrective action in the record for the system. If any time the dry-line system does not function properly, the waterline will be charged with water until repairs are made to the system and testing shows proper operation. All miners will be immediately informed of any changes in the operational status of the dry-line system.
(14) Miners will be informed of any changes in the operational status of the dry-line system prior to entering the mine if it has changed since the last shift.
(15) Pressure relief valves will be located along the waterline to relieve pressure (entrapped air) when the waterline is charging.
(16) At least 500 feet of fire hose with necessary fittings and wrenches/tools will be stored in plastic storage containers near: (a) The slope mouth on catwalk area; and (b) the slope tailpiece. The containers will be conspicuously marked as to their contents and maintained in an untangled and orderly fashion. Additional fire hose will be kept at strategic locations (approximately 150 feet apart) to ensure that any affected area along the belt can be covered from the most proximate fire hose outlet.
(17) A system will be used to continuously monitor the communications between the CO monitoring system and the automatic solenoid valves. The waterline will be immediately charged with water if the CO system fails, if the CO sensors along the slope belt stop functioning properly, or if the communication between the CO monitoring system and the automatic solenoid valves is disrupted.
(18) Prior to implementing the dry-line system specified in the terms and conditions of the Proposed Decision and Order, the petitioner will submit to the District Manager proposed revisions to the Mine Emergency Evacuation and Firefighting Program of Instruction required by 30 CFR 75.1502. The proposed revisions will address training for all miners, including those required to remotely actuate and/or reset the solenoid valves. Additionally, pursuant to 30 CFR 75.1504(b)(5), miners will be trained quarterly on the operation of the fire suppression system, and the location and use of the firefighting equipment and materials. All miners will be trained in accordance with the approved revisions prior to implementation of the system.
The petitioner asserts that the proposed alternative method will not result in a diminution of safety to the miners affected and/or otherwise provided by the existing standard.
(1) This petition will apply only to trailing cables supplying three-phase, 480-volt power for permissible pumps.
(2) The maximum length of the 480-volt power for the permissible pump will be 4000 feet.
(3) The permissible pump will be no greater than 6.2 horsepower.
(4) The KVA rating of the power center supplying power to the pump will be 500 KVA.
(5) The 480-volt power for permissible pump trailing cable will not be smaller than No. 6 American Wire Gauge (AWG).
(6) All circuit breakers used to protect the No. 6 AWG trailing cables exceeding 500 feet in length will have an instantaneous trip unit calibrated to trip at 60 amperes. The trip setting of these circuit breakers will be sealed or locked, and will have permanent, legible labels. Each label will identify the circuit breaker as being suitable for protecting No. 6 AWG cables. This label will be maintained legible.
(7) Replacement instantaneous trip units used to protect No. 6 AWG trailing cables exceeding 500 feet in length will be calibrated to trip at 60 amperes and this setting will be sealed or locked.
(8) All circuit breakers used to protect No. 2 AWG trailing cables exceeding 500 feet in length will have instantaneous trip units calibrated to trip at 150 amperes. The trip setting of these circuit breakers will be sealed or
(9) Replacement instantaneous trip units used to protect No. 2 AWG trailing cables exceeding 500 feet in length will be calibrated to trip at 150 amperes. This setting will be sealed or locked.
(10) Permanent warning labels will be installed and maintained on the cover(s) of the power center to identify the location of each sealed or locked short-circuit protection device. These labels will warn miners not to change or alter the sealed short-circuit settings.
(11) The alternative method will not be implemented until all miners designated to examine the integrity of the seals or locks, verify the short-circuit settings, and proper procedures for examining trailing cables for defects and damage have received training.
(12) Within 60 days after this proposed decision and order becomes final, the proposed revisions for the petitioner's approved 30 CFR part 48 training plan will be submitted to the District Manager. The training plan will include the following:
(a) Mining methods and operating procedures for protecting the trailing cables against damage.
(b) Proper procedures for examining the trailing cables to ensure safe operating condition.
(c) The hazards of setting the instantaneous circuit breakers too high to adequately protect the trailing cables.
(d) How to verify the circuit interrupting device(s) protecting the trailing cable(s) are properly set and maintained.
The petitioner further states that procedures specified in 30 CFR 48.3 for proposed revisions to approved training plans will apply.
The petitioner asserts that the alternative method will guarantee no less than the same measure of protection for all miners than that of the existing standard.
1. The jaw will be shut down and locked/tagged out.
2. Competent personnel will place a material dislodging implement attached to a chain in position next to the material stuck in the jaw. This will be done from a secure platform above the jaw plate opening. Fall protection will be used if necessary. The free end of the chain will be attached to the jaw crusher chassis.
3. All personnel will exit off the jaw and relocate to a safe distance away from the jaw crusher.
4. Lockouts will be removed by the applicable person(s) who will relocate to the designated safe area.
5. The jaw is started from a safe distance to allow the implement to free the material stuck in the jaw. If unsuccessful, steps 1 through 5 will be repeated.
6. Upon successfully clearing the material, the jaw will be shut down to retrieve the implement and chain.
The petitioner proposes to install cameras to allow observation of the jaw plates from the button house location. The button house is located at such distance from the jaw crusher as to not place occupants in the way of hazards associated with the material dislodging process. The dislodging implement itself will be stored in a locked cabinet when not in use. A designated competent person will have the only key to the cabinet ensuring non-authorized employees will not use the implement.
The typical procedure to remove material from between the jaw plates of a jaw crusher involves shutting down the crusher, locking out the energizing circuits, and having personnel enter the jaw opening to place hoisting devices around the material for vertical movement or extraction. The personnel's entrance into the jaw exposes them to the additional hazard of a possible shift of the material which could pin the person against the interior of the jaw or cause injuries due to trying to maneuver in a tight space.
The petitioner asserts that the intent of this proposed modification is to remove mine personnel from the hazard area thereby eliminating the chance of injury to mine personnel.
Institute of Museum and Library Services (IMLS), NFAH.
Notice of Meeting.
The National Museum and Library Services Board, which advises the Director of the Institute of Museum and Library Services on general policies with respect to the duties, powers, and authority of the Institute relating to museum, library and information services, will meet on May 9, 2013.
Thursday, May 9, 2013, from 9:00 a.m. to 2:00 p.m.
The meeting will be held at the Institute of Museum and Library Services, 1800 M Street NW., Suite 900, Washington, DC, 20036. Telephone: (202) 653–4798.
Part of this meeting will be open to the public. The rest of the meeting will be closed pursuant to subsections (c)(4) and (c)(9) of section 552b of Title 5, United States Code because the Board will consider information that may disclose: Trade secrets and commercial or financial information obtained from a person and privileged or confidential; and information the premature disclosure of which would be likely to significantly frustrate implementation of a proposed agency action.
Twenty-Seventh Meeting of the National Museum and Library Service Board Meeting: 9:00 a.m.–12:00 p.m. Twenty-Seventh National Museum and Library Services Board Meeting:
Katherine Maas, Program Specialist,
The National Science Board's Task Force on Administrative Burdens, pursuant to NSF regulations (45 CFR part 614), the National Science Foundation Act, as amended (42 U.S.C. 1862n–5), and the Government in the Sunshine Act (5 U.S.C. 552b), hereby gives notice in regard to the scheduling of a teleconference for the transaction of National Science Board business and other matters specified, as follows:
Monday, April 22, 2013, 2:30 p.m.–3:30 p.m. EDT.
The meeting will include a discussion of the Task Force's Request for Information and ongoing roundtable discussions as well as discussion related to IACUCs and IRBs, the Emerging Frontiers in Research and Innovation (EFRI) Program, and the Office of Management and Budget's recent Proposed Guidance for Federal awards.
Open.
This meeting will be held by teleconference at the National Science Board Office, National Science Foundation, 4201 Wilson Blvd., Arlington, VA 22230. A public listening room will be available for this teleconference meeting. All visitors must contact the Board Office [call 703–292–7000 or email to
Please refer to the National Science Board Web site for additional information and schedule updates. This information which may be found at
Nuclear Regulatory Commission.
Notice of availability.
Michael Raddatz, Project Manager, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Rockville, Maryland 20852; telephone: 301–492–3108; email:
The U.S. Nuclear Regulatory Commission (NRC) staff has conducted inspections of the Louisiana Energy Services (LES), LLC, National Enrichment Facility in Eunice, New Mexico, and has authorized the introduction of uranium hexafluoride (UF
The introduction of UF
Documents related to this action, including the application for amendment and supporting documentation, are available online in the NRC Library at
If you do not have access to ADAMS or if there are problems in accessing the documents located in ADAMS, contact the NRC Public Document Room (PDR) Reference staff at 1–800–397–4209, 301–415–4737 or by email to
These documents may also be viewed electronically on the public computers located at the NRC's PDR, O 1 F21, One White Flint North, 11555 Rockville Pike Rockville, MD 20852. The PDR reproduction contractor will copy documents for a fee.
For the Nuclear Regulatory Commission.
U.S. Office of Personnel Management (OPM).
Notice of amendment to system of records.
OPM has amended an existing system of records subject to the Privacy Act of 1974 (5 U.S.C. 552a) to reflect the fact that the Office of Planning and Policy Analysis (PPA) is receiving Federal Employees Health Benefits Program (FEHBP) Health Claims data directly from some FEHBP carriers, and processing and analyzing this data within OPM. PPA is developing the alternative data intake process to acquire data from plans and/or carriers that are outside of the scope of existing OPM systems.
This action will be effective without further notice on May 20, 2013 unless comments are received that would result in a contrary determination.
Send written comments by mail to the Office of Personnel Management, ATTN: Dennis Hardy, PMP, HCDW Project Manager, U. S. Office of Personnel Management, 1900 E Street NW., Room 2340A, Washington, DC 20415, or by email to
Dennis Hardy, PMP, HCDW Project Manager, 202–606–4281.
The Office of Planning and Policy Analysis, in cooperation with the OPM/Chief Information Officer (CIO), is implementing an alternate data intake and transformation infrastructure within the OPM environment to allow OPM to develop, process, and analyze this additional data in an expeditious manner. This alternate infrastructure, which is a scaled down version of the Health Claims Data Warehouse (HCDW) system, also provides a “hot site” disaster recovery capability should the primary environment be unavailable for data processing and/or analysis. This alternate infrastructure is easily scalable to support the demands of OPM. In addition to building the alternative data intake process, PPA will continue to receive carrier information from OPM's Office of Inspector General (OIG). The carrier data will be transmitted securely from the physically secured servers managed by OIG to the secure data intake infrastructure managed by OPM's OCIO. In total, PPA will be receiving data from nine plans and/or carriers. This action is necessary to meet the requirements of the Privacy Act to publish in the
The purpose of this system of records is to provide a central database from which OPM may analyze costs and utilization of services associated with FEHBP to ensure the best value for both enrollees and taxpayers. OPM collects, manages, and analyzes health services data that health insurers and administrators provide through secure data transfer for the program. OPM's analysis of the data includes the cost of care, utilization of services, and quality of care for specific population groups, geographic areas, health plans, health care providers, disease conditions, and
Health Claims Data Warehouse (HCDW).
Office of Personnel Management, 1900 E Street NW., Washington, DC 20415.
This system contains records on the Federal Employees Health Benefits Program (FEHBP). The FEHBP includes Federal employees, Postal employees, uniformed service members, retirees, and their family members who voluntarily participate in the Program.
The records in the system may contain the following types of information on participating enrollees and covered dependents:
a. Name, social security number, date of birth, gender.
b. Home address.
c. Covered dependent information (spouse, dependents)—name, social security number, date of birth, gender.
d. Enrollee's employing agency.
e. Name of health care provider.
f. Health care provider address.
g. Health care provider taxpayer identification number (TIN) or carrier identifier.
h. Health care coverage information regarding benefit coverage for the plan in which the person is enrolled.
i. Health care procedures performed on the individual in the form of ICD, CPT and other appropriate codes.
j. Health care diagnoses in the form of ICD codes, and treatments, including prescribed drugs, derived from clinical medical records.
k. Provider charges, amounts paid by the plan and amounts paid by the enrollee for the above coverage, procedures, and diagnoses.
Authority for requiring FEHBP carriers to allow OPM access to records and for requiring reports, as well as authority for OPM's maintenance of FEHBP health claims information, is provided by 5 U.S.C. 8901,
The primary purpose of this system of records is to provide a central database from which OPM may analyze the FEHBP to support the management of the program to ensure the best value for the enrollees and taxpayers. OPM collects, manages, and analyzes health services data provided by health insurers and administrators through secure data transfer. OPM analyzes the data in order to evaluate the cost of care, utilization of services, and quality of care for specific population groups, geographic areas, health plans, health care providers, disease conditions, and other relevant categories. Information contained in the database assists in improving the effectiveness and efficiency of care delivered by health care providers to the enrollees by facilitating robust contract negotiations, health plan accountability, performance management, and program evaluation. OPM uses identifiable data to create person-level longitudinal records. Access to PII is restricted to personnel needed to create person-level longitudinal records and to select OPM analysts using the database for the analytical purposes described in this notice. Only de-identified data will be released by OPM externally for all other research and analysis purposes.
1. To disclose FEHBP data to analysts inside and outside the Federal Government for the purpose of conducting analysis of health care and health insurance trends and topical health-related issues compatible with the purposes for which the records were collected and formulating health care program changes and enhancements to limit cost growth, improve outcomes, increase accountability, and improve efficiency in program administration. In all disclosures to analysts external to OPM under this routine use, only de-identified data will be disclosed. A public use file that will be maintained will only contain de-identified data and will be structured, where appropriate, to protect enrollee confidentiality where identities may be discerned because there are fewer records under certain demographic or other variables.
These records are maintained in electronic systems.
These records are retrieved by a unique identifier that will be based on identifying information (primarily name and social security number) of the individual.
The Health Claims Data Warehouse (HCDW), to include the new alternate data intake and transformation infrastructure, is operated within the OPM environment. All employees who have a need to access the information are required to have an appropriate background investigation consistent with the risk and sensitivity designation of that position. The investigation must be favorably adjudicated before they are allowed physical access to OPM and access to the HCDW system. Employees of contractors are required to have an appropriate background investigation consistent with the credentialing policy of the agency and/or the terms of the underlying contract. Again, the investigation must be favorably adjudicated before they are allowed physical access to OPM and access to the HCDW system. The OPM environment is equipped with electronic badge readers restricting
The records in this system are retained for 7 years. Computer records will be destroyed by electronic erasure. The system has been approved by NARA to maintain a 7-year record retention.
The system manager is Dennis Hardy, PMP, HCDW Project Manager, U. S. Office of Personnel Management, 1900 E Street NW., Room 2340A, Washington, DC 20415, 202–606–4281.
Individuals wishing to determine whether this system of records contains information about them may do so by writing to the U.S. Office of Personnel Management, FOIA/PA Requester Service Center, 1900 E Street NW., Room 5415, Washington, DC 20415–7900 or by emailing
1. Full name.
2. Date and place of birth.
3. Social security number.
4. Signature.
5. Available information regarding the type of information requested.
6. The reason why the individual believes this system contains information about him/her.
7. The address to which the information should be sent.
Individuals requesting access must also comply with OPM's Privacy Act regulations regarding verification of identity and access to records (5 CFR 297).
Individuals wishing to request amendment of records about them should write to the Office of Personnel Management, FOIA/PA Requester Service Center, 1900 E Street NW., Room 5415, Washington, DC 20415–7900. ATTN: Planning and Policy Analysis.
Individuals must furnish the following information in writing for their records to be located:
1. Full name.
2. Date and place of birth.
3. Social Security Number.
4. City, state, and zip code of their Federal Agency.
5. Signature.
6. Precise identification of the information to be amended.
Individuals requesting amendment must also follow OPM's Privacy Act regulations regarding verification of identity and amendment to records (5 CFR 297).
OPM, which has the authority to obtain this information from health care insurers and administrators contracted by OPM to manage the FEHBP, will obtain the FEHBP records from health care insurers and administrators. OPM's OIG also maintains the FEHBP records in a separate system of records under its own authorities.
None.
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Rule 15c3–1 requires brokers-dealers to have at all times sufficient liquid assets to meet their current liabilities, particularly the claims of customers. The rule facilitates the monitoring of the financial condition of broker-dealers by the Commission and the various self-regulatory organizations. It is estimated that broker-dealer respondents registered with the Commission and subject to the collection of information requirements of Rule 15c3–1 incur an aggregate annual time burden of 71,818 hours to comply with this rule and an aggregate annual external cost of $160,000.
Written comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's estimates of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
Please direct your written comments to: Thomas Bayer, Director/Chief Information Officer, Securities and Exchange Commission, c/o Remi Pavlik-Simon, 6432 General Green Way, Alexandria, Virginia 22312 or send an email to:
Securities and Exchange Commission (“Commission”).
Temporary order and notice of application for a permanent order under section 9(c) of the Investment Company Act of 1940 (“Act”).
Applicants have received a temporary order exempting them from section 9(a) of the Act, with respect to a guilty plea entered on April 12, 2013, by RBS Securities Japan Limited (the “Settling Firm”) in the U.S. District Court for the District of Connecticut (“District Court”) in connection with a plea agreement between the Settling Firm and the U.S. Department of Justice (“DOJ”), until the Commission takes final action on an application for a permanent order. Applicants have also applied for a permanent order.
The Royal Bank of Scotland plc (“RBS plc”), Citizens Investment Advisors (“Citizens IA”), a separately identifiable department of RBS Citizens, N.A., and the Settling Firm (each an “Applicant” and collectively, the “Applicants”).
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving Applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on May 7, 2013, and should be accompanied by proof of service on Applicants, in the form of an affidavit, or for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Elizabeth M. Murphy, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090. Applicants: RBS plc, RBS, Gogarburn, PO Box 1000, Edinburgh, EH12 1HQ, Scotland; Citizens IA, c/o RBS Citizens, N.A., Mail Stop RC 03–30, One Citizens Plaza, Providence, Rhode Island 02903; Settling Firm, Shin-Marunouchi Center Building, 1–6–2 Marunouchi, Chiyoda-ku, Tokyo 100–0005, Japan.
Bruce R. MacNeil, Senior Counsel, at (202) 551–6817 or Daniele Marchesani, Branch Chief, at (202) 551–6821 (Division of Investment Management, Exemptive Applications Office).
The following is a temporary order and a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or an applicant using the Company name box, at
1. Each Applicant is either a direct or indirect wholly-owned subsidiary of The Royal Bank of Scotland Group plc (“RBSG”). RBSG and RBS plc, a company organized under the laws of Scotland, are international banking and financial services companies that provide a wide range of products and services to companies around the world. Citizens IA, an investment adviser registered under the Investment Advisers Act of 1940, is a separately identifiable department of RBS Citizens, N.A. Citizens IA serves as investment sub-adviser to Aquila Narragansett Tax-Free Income Fund (the “Fund”) (such activity, “Fund Service Activities”). The Settling Firm, a company with its principal place of business in Tokyo, Japan, engages in securities business operations, including derivatives trading.
2. On April 12, 2013, the Fraud Section of the Criminal Division and the Antitrust Division of the DOJ filed a one-count criminal information (the “Information”) in the District Court charging one count of wire fraud, in violation of Title 18, United States Code, Section 1343. The Information charges that between approximately 2006 and at least 2010, the Settling Firm engaged in a scheme to defraud counterparties to interest rate derivatives trades executed on its behalf by secretly manipulating benchmark interest rates to which the profitability of those trades was tied. The Information charges that, in furtherance of this scheme, on or about October 5, 2009, the Settling Firm committed wire fraud in violation of Title 18, United States Code, Section 1343 by transmitting, or causing the transmission of, (i) An electronic chat between a derivatives trader employed by the Settling Firm and an RBS plc derivatives trader, (ii) a subsequent submission for the London InterBank Offered Rate for Japanese Yen (“Yen LIBOR”) to Thomson Reuters, and (iii) a subsequent publication of a Yen LIBOR rate through international and interstate wires.
3. Pursuant to a plea agreement (the “Plea Agreement”), attached as exhibit to the application, the Settling Firm entered a plea of guilty (the “Guilty Plea”) on April 12, 2013, in the District Court. In the Plea Agreement, the Settling Firm, among other things, agreed to a fine of $50 million. Applicants expect that the District Court will enter a judgment against the Settling Firm that will require remedies that are materially the same as set forth in the Plea Agreement. In addition, RBS plc entered into a deferred prosecution agreement with DOJ (the “Deferred Prosecution Agreement”) relating to submissions of the Yen LIBOR and other benchmark interest rates. In the Deferred Prosecution Agreement, RBS plc has agreed to, among other things, (i) Continue to provide full cooperation with DOJ and any other law enforcement or government agency designated by DOJ until the conclusion of all investigations and prosecutions arising out of the conduct described in the Deferred Prosecution Agreement; (ii) strengthen its internal controls as required by certain other U.S. and non-U.S. regulatory agencies that have addressed the misconduct described in the Deferred Prosecution Agreement; and (iii) the payment of $150 million, which includes amounts incurred by the Settling Firm for criminal penalties arising from the Judgment. The individuals at the Settling Firm and at any other Covered Person who were identified by the Settling Firm, RBS plc or any U.S. or non-U.S. regulatory or enforcement agencies as being responsible for the conduct underlying the Plea Agreement, including the conduct described in any of the exhibits
1. Section 9(a)(1) of the Act provides, in pertinent part, that a person may not serve or act as an investment adviser or depositor of any registered investment company or a principal underwriter for any registered open-end investment company or registered unit investment trust, if such person within ten years has been convicted of any felony or misdemeanor arising out of such person's conduct, as, among other things, a broker or dealer. Section 2(a)(10) of the Act defines the term “convicted” to include a plea of guilty. Section 9(a)(3) of the Act extends the prohibitions of section 9(a)(1) to a company any affiliated person of which has been disqualified under the provisions of section 9(a)(1). Section 2(a)(3) of the Act defines “affiliated person” to include, among others, any person directly or indirectly controlling, controlled by, or under common control with, the other person. Applicants state that the Settling Firm is an affiliated person of each of the other Applicants within the meaning of section 2(a)(3). Applicants state that the Guilty Plea would result in a disqualification of each Applicant for ten years under section 9(a) of the Act because the Settling Firm would become the subject of a conviction described in 9(a)(1).
2. Section 9(c) of the Act provides that the Commission shall grant an application for exemption from the disqualification provisions of section 9(a) if it is established that these provisions, as applied to Applicants, are unduly or disproportionately severe or that the Applicants' conduct has been such as not to make it against the public interest or the protection of investors to grant the exemption. Applicants have filed an application pursuant to section 9(c) seeking temporary and permanent orders exempting the Applicants and the other Covered Persons from the disqualification provisions of section 9(a) of the Act.
3. Applicants believe they meet the standard for exemption specified in section 9(c). Applicants state that the prohibitions of section 9(a) as applied to them would be unduly and disproportionately severe and that the conduct of Applicants has been such as not to make it against the public interest or the protection of investors to grant the exemption from section 9(a).
4. Applicants assert that the Conduct did not involve any of the Applicants' Fund Service Activities, and that the Settling Firm does not serve in any of the capacities described in section 9(a) of the Act. Additionally, Applicants assert that the Conduct did not involve the Fund or the assets of the Fund. Applicants further assert that (i) None of the current or former directors, officers or employees of the Applicants (other than certain personnel of the Settling Firm and RBS plc who were not involved in any of the Applicants' Fund Service Activities) had any knowledge of, or had any involvement in, the Conduct; (ii) no former employee of the Settling Firm or of any other Covered Person who previously has been or who subsequently may be identified by the Settling Firm, RBS plc or any U.S. or non-U.S. regulatory or enforcement agencies as having been responsible for the Conduct will be an officer, director, or employee of any Applicant or of any other Covered Person; (iii) no employee of the Settling Firm or of any Covered Person who was involved in the Conduct had any, or will not have any future, involvement in the Covered Persons' activities in any capacity described in section 9(a) of the Act; and (iv) because the personnel of the Applicants (other than certain personnel of the Settling Firm and RBS plc who were not involved in any of the Applicants' Fund Service Activities) did not have any involvement in the Conduct, shareholders of the Fund were not affected any differently than if the Fund had received services from any other non-affiliated investment adviser. Applicants have agreed that neither they nor any of the other Covered Persons will employ any of the former employees of the Settling Firm or any other Covered Person who previously have been or who subsequently may be identified by the Settling Firm, RBS plc or any U.S. or non-U.S. regulatory or enforcement agency as having been responsible for the Conduct in any capacity without first making a further application to the Commission pursuant to section 9(c).
5. Applicants further represent that the inability of Citizens IA to continue providing Fund Service Activities would result in potential hardships for both the Fund and its shareholders. Applicants state that they will distribute written materials, including an offer to meet in person to discuss the materials, to the board of trustees of the Fund, including the directors who are not “interested persons,” as defined in section 2(a)(19) of the Act, of such Fund, and their independent legal counsel as defined in rule 0–1(a)(6) under the Act, if any, regarding the Guilty Plea, any impact on the Fund, and the application. The Applicants will provide the Fund with all information concerning the Plea Agreement and the application that is necessary for the Fund to fulfill its disclosure and other obligations under the federal securities laws.
6. Applicants also state that, if Citizens IA was barred from providing Fund Service Activities to the Fund, the effect on its business and employees would be severe.
7. Applicants state that none of the Applicants has previously applied for an exemptive order under section 9(c) of the Act.
Applicants agree that any order granted by the Commission pursuant to the application will be subject to the following conditions:
1. Any temporary exemption granted pursuant to the application shall be without prejudice to, and shall not limit the Commission's rights in any manner with respect to, any Commission investigation of, or administrative proceedings involving or against, Covered Persons, including, without limitation, the consideration by the Commission of a permanent exemption from section 9(a) of the Act requested pursuant to the application or the revocation or removal of any temporary exemptions granted under the Act in connection with the application.
2. Neither the Applicants nor any of the other Covered Persons will employ any of the former employees of the Settling Firm or of any other Covered Person who previously has been or who subsequently may be identified by the Settling Firm, RBS plc or any U.S. or non-U.S. regulatory or enforcement agency as having been responsible for the Conduct, in any capacity, without first making a further application to the Commission pursuant to section 9(c).
The Commission has considered the matter and finds that the Applicants have made the necessary showing to justify granting a temporary exemption.
Accordingly
By the Commission.
Securities and Exchange Commission (“Commission”).
Notice of an application under section 6(c) of the Investment Company Act of 1940 (“Act”) for an exemption from section 15(a) of the Act and rule 18f–2 under the Act, as well as from certain disclosure requirements.
Applicants request an order that would permit them to enter into and materially amend subadvisory agreements without shareholder approval and that would grant relief from certain disclosure requirements.
Trust for Professional Managers (the “Trust”) and Aurora Investment Management L.L.C. (the “Initial Advisor”).
The application was filed January 17, 2013, and amended on April 3, 2013.
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on May 7, 2013, and should be accompanied by proof of service on the applicants, in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Elizabeth M. Murphy, Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549–1090. Applicants: John P. Buckel, Trust for Professional Managers, 615 East Michigan Street, Milwaukee, WI 53202; Scott M. Montpas, Esq., Aurora Investment Management L.L.C., 300 North LaSalle Street, 52nd Floor, Chicago, IL 60654.
Courtney S. Thornton, Senior Counsel, at (202) 551–6812 or David P. Bartels, Branch Chief, at (202) 551–6821 (Division of Investment Management, Exemptive Applications Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or for an applicant using the Company name box, at
1. The Trust, a Delaware statutory trust, is registered under the Act as an open-end management investment company. The Trust is organized as a series investment company and currently consists of 28 series, one of which is advised by the Initial Advisor.
2. Under the terms of each Advisory Agreement, the Advisor will provide each Fund with overall management services and, as it deems appropriate, will continuously review, supervise and administer each Fund's investment program, subject to the supervision of, and policies established by, the Board. For the investment management services it will provide to each Fund, the Advisor will receive the fee specified in the Advisory Agreement from such Fund, payable monthly at an annual rate based on the average daily net assets of the Fund. The Advisory Agreement permits the Advisor to delegate certain responsibilities to one or more subadvisors (each a “Subadvisor”), subject to the approval of the Board.
3. Each Subadvisor will be an investment adviser as defined in section 2(a)(20) of the Act and will be registered with the Commission as an “investment adviser” under the Advisers Act. The Advisor will evaluate, allocate assets to and oversee the Subadvisors, and make recommendations about their hiring, termination, and replacement to the Board, at all times subject to the authority of the Board. The Advisor will compensate the Subadvisors out of the advisory fee paid by a Fund to the Advisor under the Advisory Agreement.
4. Applicants request an order to permit the Advisor, subject to Board approval, to select certain Subadvisors to manage all or a portion of the assets of a Fund or Funds pursuant to a Subadvisory Agreement and materially
5. Applicants also request an order exempting the Funds from certain disclosure provisions described below that may require the applicants to disclose fees paid by the Advisor to each Subadvisor. Applicants seek an order to permit the Trust to disclose for a Fund (as both a dollar amount and as a percentage of the Fund's net assets): (a) The aggregate fees paid to the Advisor and any Affiliated Subadvisor; and (b) the aggregate fees paid to Subadvisors other than Affiliated Subadvisors (collectively, “Aggregate Fee Disclosure”). Any Fund that employs an Affiliated Subadvisor will provide separate disclosure of any fees paid to the Affiliated Subadvisor.
1. Section 15(a) of the Act provides, in relevant part, that is unlawful for any person to act as an investment adviser to a registered investment company except pursuant to a written contract that has been approved by a vote of a majority of the company's outstanding voting securities. Rule 18f–2 under the Act provides that each series or class of stock in a series investment company affected by a matter must approve that matter if the Act requires shareholder approval.
2. Form N–1A is the registration statement used by open-end investment companies. Item 19(a)(3) of Form N–1A requires disclosure of the method and amount of the investment adviser's compensation. Applicants state that this provision may require a Fund to disclose the fees the Advisor pays to each Subadvisor.
3. Rule 20a–1 under the Act requires proxies solicited with respect to a registered investment company to comply with Schedule 14A under the Securities Exchange Act of 1934. Items 22(c)(1)(ii), 22(c)(1)(iii), 22(c)(8) and 22(c)(9) of Schedule 14A, taken together, require a proxy statement for a shareholder meeting at which the advisory contract will be voted upon to include the rate of compensation of the investment adviser, the aggregate amount of the investment adviser's fees, a description of the terms of the contract to be acted upon, and, if a change in the advisory fee is proposed, the existing and proposed fees and the difference between the two fees. Applicants believe that these provisions may require a Fund to disclose the fees the Advisor pays to each Subadvisor in proxy statements for shareholder meetings at which fees would be established, or action would be taken on an advisory contract.
4. Regulation S–X sets forth the requirements for financial statements required to be included as part of a registered investment company's registration statement and shareholder reports filed with the Commission. Sections 6–07(2)(a), (b), and (c) of Regulation S–X require a registered investment company to include in its financial statement information about investment advisory fees. Applicants state that these provisions may be deemed to require the Funds' financial statements to include information concerning fees paid to the Subadvisors.
5. Section 6(c) of the Act provides that the Commission may exempt any person, security, or transaction or any class or classes of persons, securities, or transactions from any provisions of the Act, or from any rule thereunder, if such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Applicants state that the requested relief meets this standard for the reasons discussed below.
6. Applicants state that, by investing in a Fund, shareholders will hire the Advisor to manage the Fund's assets in conjunction with using its investment subadvisor selection and monitoring process. Applicants assert that, from the perspective of the shareholder, the role of the Subadvisors is substantially equivalent to that of the individual portfolio managers employed by traditional investment company advisory firms. Applicants believe that requiring shareholder approval of each Subadvisory Agreement would impose unnecessary delays and expenses on the Funds and may preclude the Funds from acting promptly when the Advisor and Board consider it appropriate to hire Subadvisors or amend Subadvisory Agreements. Applicants note that the Advisory Agreements and any Subadvisory Agreements with Affiliated Subadvisors will remain subject to the shareholder approval requirements of section 15(a) of the Act and rule 18f–2 under the Act.
7. If a new Subadvisor is retained in reliance on the requested order, the Funds will inform shareholders of the hiring of a new Subadvisor pursuant to the following procedures (“Modified Notice and Access Procedures”): (a) Within 90 days after a new Subadvisor is hired for any Fund, that Fund will send its shareholders either a Multi-manager Notice or a Multi-manager Notice and Multi-manager Information Statement;
A “Multi-manager Information Statement” will meet the requirements of Regulation 14C, Schedule 14C and Item 22 of Schedule 14A under the Exchange Act for an information statement, except as modified by the requested order to permit Aggregate Fee Disclosure. Multi-manager Information Statements will be filed electronically with the Commission via the EDGAR system.
8. Applicants assert that the requested disclosure relief will benefit shareholders of the Funds because it will improve the Advisor's ability to negotiate the fees paid to Subadvisors. Applicants state that the Advisor may be able to negotiate rates that are below a Subadvisor's “posted” amounts if the Advisor is not required to disclose the Subadvisors' fees to the public.
Applicants agree that any order granting the requested relief will be subject to the following conditions:
1. Before a Fund may rely on the order requested in the application, the operation of the Fund in the manner described in the application will be approved by a majority of the Fund's outstanding voting securities, as defined in the Act, or, in the case of a Fund whose public shareholders purchase shares on the basis of a prospectus containing the disclosure contemplated by condition 2 below, by the sole initial shareholder before offering the Fund's shares to the public.
2. The prospectus for each Fund will disclose the existence, substance, and effect of any order granted pursuant to the application. Each Fund will hold itself out to the public as employing the Manager of Managers Structure described in the application. The prospectus will prominently disclose that the Advisor has ultimate responsibility (subject to oversight by the Board) to oversee the Subadvisors and recommend their hiring, termination, and replacement.
3. Funds will inform shareholders of the hiring of a new Subadvisor within 90 days after the hiring of a new Subadvisor pursuant to the Modified Notice and Access Procedures.
4. The Advisor will not enter into a Subadvisory Agreement with any Affiliated Subadvisor without that agreement, including the compensation to be paid thereunder, being approved by the shareholders of the applicable Fund.
5. At all times, at least a majority of the Board will be Independent Trustees, and the nomination and selection of new or additional Independent Trustees will be placed within the discretion of the then-existing Independent Trustees.
6. When a Subadvisor change is proposed for a Fund with an Affiliated Subadvisor, the Board, including a majority of the Independent Trustees, will make a separate finding, reflected in the applicable Board minutes, that such change is in the best interests of the Fund and its shareholders and does not involve a conflict of interest from which the Advisor or the Affiliated Subadvisor derives an inappropriate advantage.
7. Independent legal counsel, as defined in rule 0–1(a)(6) under the Act, will be engaged to represent the Independent Trustees. The selection of such counsel will be within the discretion of the then existing Independent Trustees.
8. Each Advisor will provide the Board, no less frequently than quarterly, with information about the profitability of the Advisor on a per-Fund basis. The information will reflect the impact on profitability of the hiring or termination of any Subadvisor during the applicable quarter.
9. Whenever a Subadvisor is hired or terminated, the Advisor will provide the Board with information showing the expected impact on the profitability of the Advisor.
10. The Advisor will provide general management services to each Fund, including overall supervisory responsibility for the general management and investment of the Fund's assets and, subject to review and approval of the Board, will (i) set each Fund's overall investment strategies; (ii) evaluate, select and recommend Subadvisors to manage all or part of a Fund's assets; (iii) when appropriate, allocate and reallocate a Fund's assets among multiple Subadvisors; (iv) monitor and evaluate the performance of Subadvisors; and (v) implement procedures reasonably designed to ensure that the Subadvisors comply with each Fund's investment objective, policies and restrictions.
11. No trustee or officer of the Trust, or of a Fund, or director or officer of the Advisor, will own directly or indirectly (other than through a pooled investment vehicle that is not controlled by such person) any interest in a Subadvisor, except for (a) ownership of interests in the Advisor or any entity that controls, is controlled by, or is under common control with the Advisor; or (b) ownership of less than 1% of the outstanding securities of any class of equity or debt of a publicly traded company that is either a Subadvisor or an entity that controls, is controlled by, or is under common control with a Subadvisor.
12. Each Fund will disclose in its registration statement the Aggregate Fee Disclosure.
13. In the event the Commission adopts a rule under the Act providing substantially similar relief to that in the order requested in the application, the requested order will expire on the effective date of that rule.
For the Commission, by the Division of Investment Management, under delegated authority.
On February 12, 2013, BATS Y-Exchange, Inc. (the “Exchange” or “BYX”) filed with the Securities and Exchange Commission (“Commission”) pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
Section 19(b)(2) of the Act
The Commission is extending the 45-day time period for Commission action on the proposed rule change. The Commission finds that it is appropriate to designate a longer period to take action on the proposed rule changes so that it has sufficient time to consider the Exchange's proposal, which would lessen the attestation requirements of
Accordingly, the Commission, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On February 13, 2013, the International Securities Exchange, LLC (the “Exchange” or the “ISE”) filed with the Securities and Exchange Commission (the “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”)
The Exchange proposes to amend its rules to provide for the listing and trading on the Exchange of options on one foreign currency index—the Dow Jones FXCM Dollar Index (the “Dollar Index”). Options on the Dollar Index will be settled in the same manner as the Exchange's foreign currency options (“FX Options”)
The Dollar Index is calculated and maintained by Dow Jones Indexes, a unit of CME Group. The components that comprise the Dollar Index include a subset of the modified exchange rates
Spot currency quotes are derived from Thomson Reuters, the same source that the Exchange currently uses for the underlying values of its existing FX Options. Each input value is based on the mid-point between the bid and ask quotes. The Dollar Index has a base date of January 1, 2011, using closing prices as of December 31, 2010. The base value of the Dollar Index is 10,000. Spot quotes for each currency pair on the base date are as follows:
On its base date, the Dollar Index was set to be equally-weighted such that each constituent currency pair has equal influence on the overall index value. This method is similar to equally-weighted stock indexes that calculate the number of shares needed in order for each stock constituent to have an equal position. The Dollar Index is designed to reflect spot positions in each currency with the weighting of each currency set as equal at inception and rebalancing events. Rebalancing events are not scheduled. The Dollar Index would be rebalanced if, for example, the value of any position were to fall below $1,000 (i.e., loses 90 percent of its original $10,000 position value), or in response to extraordinary events affecting the global currency market.
As noted above, the Dollar Index will be maintained and calculated by Dow Jones. The level of the Dollar Index will reflect the current exchange rates of the four underlying currency pairs. The Dollar Index will be updated on a real-time basis beginning at 6:15 p.m. each day and ending at 5:00 p.m. (New York time) the following day from Sunday through Friday. If the value of a component's exchange rate is not available, the last known exchange rate will be used in the calculation.
The Exchange represents that values of the Dollar Index will be disseminated every 15 seconds during the Exchange's regular trading hours to market information vendors such as Bloomberg and Thomson Reuters.
As part of this proposal, the Exchange also is making a clarifying change to ISE Rule 2003(b) by replacing the word “stocks” with “components” because index options listed by the Exchange are no longer limited to having stocks as their underlying components; with this proposed rule change, the Exchange also will list options on indexes that have currencies as their underlying components.
Options on the Dollar Index will expire on the Saturday following the third Friday of the expiration month. Trading in expiring options on the Dollar Index will normally cease at
The Dollar Index is a foreign currency index, as defined in proposed Rule 2001(h). Options on the Dollar Index are European-style and cash-settled.
The trading of options on the Dollar Index will be subject to the trading halt procedures applicable to index options traded on the Exchange.
The Exchange proposes to list options on the Dollar Index that may expire at three-month intervals or in consecutive months. The Exchange also may list up to six expiration months at any one time. The Exchange proposes to set strike price intervals for options on the Dollar Index at minimum intervals of 2
The Exchange may open for trading additional series of the same class of options on the Dollar Index as the current value of the underlying index moves substantially from the exercise price of those options on the Dollar Index that already have been opened for trading on the Exchange. The Exchange also may open for trading additional series of options on the Dollar Index that are more than thirty percent (30%) away from the current index value, provided that demonstrated customer interest exists for such series, as expressed by institutional, corporate, or individual customers or their brokers. The Exchange will not consider Market makers trading for their own account when determining customer interest under this provision.
The Exchange proposes to adopt the minimum tick size of $0.01 for options on the Dollar Index. Accordingly, the Exchange proposes to amend Supplementary Material .02 to ISE Rule 710 to permit options on the Dollar Index to be quoted and traded in one-cent increments. The Exchange believes that this trading increment will result in narrower spreads for options on the Dollar Index than if traditional trading increments are used because options on the individual foreign currency pairs that make up the Dollar Index are quoted in $0.01 increments.
For options on the Dollar Index, the Exchange proposes to establish aggregate position limits at 600,000 contracts on the same side of the market, provided no more than 300,000 of such contracts are in the nearest expiration month series. The Exchange notes that the proposed positions limits for the Dollar Index are equal to or lower than the position limits for individual FX options on the four currency pairs comprising the Dollar Index.
The Exchange proposes to list options on the Dollar Index in the three consecutive near-term expiration months plus up to three successive expiration months in the March cycle. For example, consecutive expirations of January, February, March, plus June, September, and December expirations would be listed.
The trading of options on the Dollar Index will be subject to the same rules that presently govern the trading of Exchange index options, including sales practice rules, margin requirements, trading rules, and position and exercise limits. In addition, long-term option series having up to sixty months to expiration may be traded.
The Exchange represents that it has an adequate surveillance program in place for options traded on the Dollar Index, and intends to apply those same program procedures that it applies to the Exchange's other options products.
The Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission believes that the listing and trading of options on the Dollar Index will provide additional trading opportunities for investors in an index that reflects U.S. Dollar fluctuations against a basket of four highly liquid currencies (the euro, British pound, Japanese yen, and the Australian dollar). Investors will be able to trade this product through their existing broker-dealer on the Exchange and will be able to benefit from any investor safeguards incorporated into the Exchange's rules.
In addition, the Commission believes that allowing options on the Dollar Index to trade in penny ($0.01) increments is appropriate and consistent with the Act.
The Exchange has represented that it has an adequate surveillance program in place for options on the Dollar Index and intends to apply the same procedures for surveillance that it applies to its other index options.
The proposed listing standards require the current value of the Dollar Index to be widely disseminated at least once every 15 seconds by one or more major market data vendors during the time options on the index are traded on the Exchange. The Exchange, moreover, has represented that the total number of components in the Dollar Index will not decrease from the number of components in the Dollar Index at the time of its initial listing.
The Commission notes that the Exchange proposes to apply its existing index rules regarding the listing of new series and additional series to options on the Dollar Index. Specifically, exercise prices will be required to be reasonably related to the value of the underlying index and generally must be within 30% of the current index value.
In addition, the Exchange has stated that options on the Dollar Index would be subject to the same rules that govern all Exchange index options, including rules that are designed to protect public customer trading.
The Commission believes that the Exchange's proposed position and exercise limits, strike price intervals, margin, and other aspects of the proposed rule change are appropriate and consistent with the Act. The Commission notes that the proposed position limits for the Dollar Index are equal to or lower than the position limits for individual foreign currency options on the four currency pairs comprising the Dollar Index.
exercise limits for options on the Dollar Index.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act” or “Exchange Act”)
The Exchange proposes to amend IM–7080–1 (Trading Conditions During Limit State or Straddle State) to permit the Exchange to suspend certain provisions in BOX Rule 7170 (Obvious and Catastrophic Errors) during limit up-limit down states in securities that underlie options traded on the Exchange on a pilot basis. The text of the proposed rule change is available from the principal office of the Exchange, at the Commission's Public Reference Room and also on the Exchange's Internet Web site at
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The self-regulatory organization has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend IM–7080–1 (Trading Conditions During Limit State or Straddle State) to permit the Exchange to suspend certain provisions in BOX Rule 7170 (Obvious and Catastrophic Errors) during limit up-limit down states in securities that underlie options traded on the Exchange on a pilot basis. This is a competitive filing that is based on a proposal recently submitted by International Securities Exchange, LLC (“ISE”) and approved by the Commission.
On May 31, 2012, the Commission approved the Plan to Address Extraordinary Market Volatility (the “Plan”),
BOX is not a participant in the Plan because it does not trade NMS Stocks. However, BOX trades options contracts overlying NMS Stocks. Because options pricing models are highly dependent on the price of the underlying security and the ability of options traders to effect hedging transactions in the underlying security, the implementation of the Plan will impact the trading of options classes traded on the Exchange. Specifically, under the Plan, upper and lower price bands will be calculated based on a reference price for each NMS Stock.
When the national best bid (offer) for a security underlying an options class is non-executable, the ability for options market participants to purchase (sell) shares of the underlying security and the price at which they may be able to purchase (sell) shares will become uncertain, as there will be a lack of transparency regarding the availability of liquidity for the security.
The Exchange proposes to exclude transactions executed during a Limit State or Straddle State from certain provisions in BOX Rule 7170, on a one-year pilot basis. This will not include Rule 7170(e) and (f), which specify when a trade resulting from an erroneous print or quote in the underlying security may be adjusted or busted.
The remaining provisions in BOX Rule 7170 provide a process by which a transaction may be busted or adjusted
After careful consideration, the Exchange believes the application of the current provisions in Rule 7170 would be impracticable given the lack of a reliable national best bid or offer in the options market during Limit States and Straddle States, and produce undesirable effects. Pursuant to Rule 7170, market participants have five minutes (in the case of a Market Maker) and 20 minutes (in the case of a non-Market Maker Options Participant) to notify the Exchange to review a transaction as an obvious error under 7170(g)(1) and Participants have until 8:30 a.m. the following day to request that the Exchange review a trade as a catastrophic error under Rule 7170(h)(1).
The Exchange notes that there are additional protections in place outside of the Obvious and Catastrophic Error Rule that will continue to safeguard customers. First, SEC Rule 15c3–5 requires that, “financial risk management controls and supervisory procedures must be reasonably designed to prevent the entry of orders that exceed appropriate pre-set credit or capital thresholds, or that appear to be erroneous.”
The Exchange notes that Rule 15010 (Order Protection) will continue to apply during Limit and Straddle States. Accordingly, only orders identified as Intermarket Sweep Orders will trade through protected bids and offers during Limit and Straddle States, and as a result, the only trades that would potentially have been reviewed under Rule 7170 during Limit and Straddle States are those involving Intermarket Sweep Orders. The Exchange believes that this is an additional factor that supports its proposal to suspend certain provisions in Rule 7170 during Limit and Straddle States.
The Exchange proposes to review the operation of this proposal during the one-year pilot period from the operative date and analyze the impact of the Limit and Straddle States accordingly.
Additionally, the Exchange represents that it will conduct its own analysis concerning the elimination of the obvious error rule during Limit and Straddle States and agrees to provide the Commission with relevant data to assess the impact of this proposed rule change. As part of its analysis, the Exchange will evaluate (1) the options market quality during Limit and Straddle States, (2) assess the character of incoming order flow and transactions during Limit and Straddle States, and (3) review any complaints from members and their customers concerning executions during Limit and Straddle States. The Exchange also agrees to provide to the Commission data requested to evaluate the impact of the elimination of the obvious error rule, including data relevant to assessing the various analyses noted above. The Exchange notes that these proposed changes are consistent with the views of the Securities Industry and
Specifically, the Exchange agrees to provide the following data to the Commission to help evaluate the impact of the proposal. At least two months prior to the end of the pilot period the Exchange shall provide an assessment that evaluates the statistical and economic impact of Straddle States on liquidity and market quality in the options markets; and assess whether the lack of obvious error rules in effect during the Straddle and Limit States is problematic. On a monthly basis, the Exchange shall provide both the Commission and public a dataset containing the data for each Straddle and Limit State in optionable stocks.
The Exchange believes that the proposal is consistent with the requirements of Section 6(b) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange believes that it is necessary and appropriate in the interest of promoting fair and orderly markets to exclude transactions executed during a Limit State or Straddle State from the provision of BOX Rule 7170. The Exchange believes the application of the current rule will be impracticable given the lack of a reliable national best bid or offer in the options market during Limit States and Straddle States, and that the resulting actions (
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. In this regard and as indicated above, the Exchange notes that the rule change is being proposed as a competitive response to a filing submitted by ISE that was recently approved by the Commission.
The Exchange has neither solicited nor received comments on the proposed rule change.
Because the foregoing proposed rule change does not significantly affect the protection of investors or the public interest, does not impose any significant burden on competition, and, by its terms, does not become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
The Exchange has requested that the Commission waive the 30-day operative delay. The Commission believes that waiver of the operative delay is consistent with the protection of investors and the public interest because the proposal is substantially similar to those of other exchanges that have been approved by the Commission to exclude transactions executed during a Limit State or Straddle State from certain provisions of the obvious error rules.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send paper comments in triplicate to Elizabeth M. Murphy, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549–1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
The Department of State issued a Presidential Permit to the State of Michigan on April 11, 2013, authorizing the permitee to construct, connect, operate and maintain at the border of the United States a bridge linking Detroit, Michigan and Windsor, Ontario. In making this determination, the Department provided public notice of the proposed amendment (77 FR 7951, July 11, 2012), offered the opportunity for comment and consulted with other federal agencies, as required by Executive Order 11423, as amended.
Josh Rubin, Canada Border Affairs Officer, via email at
The following is the text of the issued permit:
By virtue of the authority vested in me as Under Secretary of State for Economic Growth, Energy, and the Environment, including those authorities under Executive Order 11423, 33 FR 11741, as amended by Executive Order 12847 of May 17, 1993, 58 FR 29511, Executive Order 13284 of January 23, 2003, 68 FR 4075, and Executive Order 13337 of April 30, 2004, 69 FR 25299; and Department of State Delegation of Authority 118–2 of January 26, 2006; having considered the environmental effects of the proposed action consistent with the National Environmental Policy Act of 1969 (83 Stat. 852; 42 U.S.C. 4321 et seq.) and other statutes relating to environmental concerns; having considered the proposed action consistent with the National Historic Preservation Act (80 Stat. 917, 16 U.S.C. 470f et seq.); and having requested and received the views of various of the federal departments and other interested persons; I hereby grant permission, subject to the conditions herein set forth, to the State of Michigan (hereinafter referred to as “permittee ”) to construct, connect, operate, and maintain a new international bridge (the New International Trade Crossing) between Detroit, Michigan, and Windsor, Ontario, Canada.
The term “facilities” as used in this permit means the bridge and any land, structure, or installations appurtenant thereto, at the location set forth in the Preferred Alternative in the “Detroit River International Crossing (DRIC), Wayne County, Michigan, Final Environmental Impact Statement and Final Section 4(f) Evaluation” by the U.S. Department of Transportation, Federal Highway Administration and Michigan Department of Transportation, dated November 21, 2008, the Record of Decision of the Federal Highway Administration dated January 14, 2009, and the application for a Presidential permit submitted by the State of Michigan dated June 18, 2012.
The term “United States facilities” as used in this permit means that part of the facilities in the United States.
This permit is subject to the following conditions:
(2) The construction, operation and maintenance of the United States facilities shall be in all material respects as described in the permitee's June 18, 2012, application for a Presidential Permit (the “Application”).
(2) Prior to initiation of construction, the permittee shall obtain the approval of the United States Coast Guard (USCG) in conformity with Section 5 of the International Bridge Act of 1972 (33 U.S.C. 535c), 33 CFR 1.01–60 and Department of Homeland Security Delegation of Authority Number 0170.1.
(2) The permittee shall save harmless and indemnify the United States from any claimed or adjudged liability arising out of the construction, operation, or maintenance of the facilities.
(3) The permittee shall maintain the United States facilities and every part thereof in a condition of good repair for their safe operation.
(2) The permittee shall reach agreement with U.S. Customs and Border Protection (CBP) and other U.S. Federal Inspection Agencies on the provision of suitable facilities for officers to perform their duties. Such facilities shall meet the latest agency design standards and operational requirements including as necessary, but not limited to, inspection and office space, personnel parking and restrooms, an access road, kennels, and other operationally-required components.
(2) The permittee shall not undertake any change to the design of the bridge, or any construction activity, that would result in temporary or permanent obstructions affecting the natural level or flow of boundary waters before obtaining written confirmation from the Department of State that the requirements of the 1909 Treaty Between the United States and Great Britain Relating to Boundary Waters, and Questions Arising Between the United States and Canada, have been satisfied.
The Federal Aviation Administration (FAA) invites federal employees, aviation professionals and all others interested in FAA NextGen technologies to attend and participate in an Aircraft Access to SWIM Working Group Meeting scheduled for Thursday, May 16, 2013 from 1:00 p.m. to 4:00 p.m. in the Bessie Coleman Room (Second Floor) at the FAA Headquarters Building in Washington DC To attend and follow security procedures, participants must register for the meeting by sending an email to
The FAA's Next Generation Air Transportation System (NextGen) program is a comprehensive modernization of our National Airspace System (NAS). It is intended to provide new aviation capabilities for both users and operators by improving aviation safety, system capacity and throughput.
The FAA's System Wide Information Management (SWIM) program is one of seven transformational programs of the NextGen portfolio. SWIM is designed to utilize a Service Oriented Architecture (SOA) to exchange aviation data and services without the restrictive, time consuming and expensive process of developing unique interfaces for the multitude of systems and equipment used by the NAS.
The Aircraft Access to SWIM (AAtS) initiative is the airborne component of the SWIM SOA. AAtS will allow aircraft to exchange operational information such as: weather, airport information, and other services during all phases of flight. This AAtS capability is significant in that near real time NAS data will now be available to support strategic and tactical traffic management and flight operations.
AAtS will provide aircraft with a means to obtain a common collection of aeronautical services provided from multiple sources. These sources include the FAA, DHS, NWS, and other information sources to create a shared aviation information environment. The AAtS initiative will utilize commercial air/ground network providers' infrastructure to exchange data between aircraft and the NAS ground facilities. The FAA in collaboration with industry users will define the set of operational and technical requirements that will be used to drive that infrastructure.
The AAtS initiative will facilitate common situational awareness between the aircraft flight crews and traffic managers, which will result in better decision making and more efficient NAS operations. AAtS will work to ensure safe, secure, dependable, and hassle-free travel; while reducing energy use, emissions and the impact of aviation on the environment.
Federal Aviation Administration, DOT.
Notice of request to release airport land.
The Federal Aviation Administration (FAA) proposes to rule and invites public comment on the application for a release of approximately 6.50 acres of airport property at the Oroville Municipal Airport (OVE), Oroville, California from all conditions contained in the Surplus Property Deed and Grant Assurances because the parcel of land is not needed for airport purposes. The land requested to be released is located outside of the airport fence along the southern boundary of the airport. The release will allow the City of Oroville (City) to sell the property at its fair market value, thereby benefiting the Airport and serving the interest of civil aviation. The City is also requesting a land-use change for approximately 13.62 acres of land adjacent to the 6.50 acres so it may be leased at its fair market value for non-aeronautical purposes to earn revenue for the airport. The proposed use will be compatible with the airport and will not interfere with the airport or its operation.
Comments must be received on or before May 20, 2013.
Comments on the request may be mailed or delivered to the FAA at the following address: Robert Lee, Airports Compliance Specialist, Federal Aviation Administration, San Francisco Airports District Office,
In accordance with the Wendell H. Ford Aviation Investment and Reform Act for the 21st Century (AIR 21), Public Law 106–181 (Apr. 5, 2000; 114 Stat. 61), this notice must be published in the
The following is a brief overview of the request:
The City of Oroville, California requested a release from Federal surplus property and grant assurance obligations for approximately 6.50 acres of airport land to allow for its sale and a land-use change for approximately 13.62 acres of airport land for long term leasing for non-aeronautical revenue generating purposes. The property was originally acquired pursuant to the Surplus Property Act of 1944 and was deeded to the City of Oroville on May 9, 1947. The parcels of land are located south of the airfield, outside of the airport fence line; and along the southern perimeter of the Airport near Larkin Road.
The City of Oroville will sell the 6.50 acres of property at fair market value and lease 13.62 acres of undeveloped airport land for fair market rental value for non-aeronautical revenue producing purposes.
The sales proceeds and rental income will be devoted to airport operations and capital projects. The reuse of the property will not interfere with the airport or its operation; thereby serve the interests of civil aviation.
National Highway Traffic Safety Administration (NHTSA), DOT.
Notice of proposed extension, without change, of a currently approved collection of information.
Before a Federal agency can collect certain information from the public, the agency must receive approval from the Office of Management and Budget (“OMB”). Under procedures established by the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), before seeking OMB approval, Federal agencies must solicit public comment on proposed collections of information, including extensions and reinstatements of previously approved collections. In compliance with the Paperwork Reduction Act of 1995, this notice describes one collection of information for which NHTSA intends to seek OMB approval.
Comments must be submitted on or before June 17, 2013.
You may submit comments to the docket number identified in the heading of this document by any of the following methods:
•
•
•
•
Regardless of how you submit your comments, please be sure to mention the docket number of this document and cite OMB Clearance No. 2127–0609, “Criminal Penalty Safe Harbor Provision.”
You may call the Docket at 202–366–9322.
Note that all comments received will be posted without change to
For questions please contact Mr. John Piazza in the Office of the Chief Counsel at the National Highway Traffic Safety Administration, telephone (202) 366–9511. Please identify the relevant collection of information by referring to OMB Clearance Number 2127–0609 “Criminal Penalty Safe Harbor Provision.”
Under the Paperwork Reduction Act of 1995, before an agency submits a proposed collection of information to OMB for approval, it must publish a document in the
(i) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(ii) the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(iii) how to enhance the quality, utility, and clarity of the information to be collected; and
(iv) how to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
In compliance with these requirements, NHTSA asks public comment on the following proposed extension, without change, of a currently approved collection of information:
We believe that there will be very few criminal prosecutions under section 30170, given its elements. Since the safe harbor related rule has been in place, the agency has not received any reports. Accordingly, it is not likely to be a substantial motivating force for a submission of a proper report. We estimate that no more than one such person a year would invoke this new collection of information, and we do not anticipate receiving more than one report a year from any particular person.
As stated before, we estimate that no more than one person a year would be subject to this collection of information. Incrementally, we estimate that on average it will take no longer than two hours for a person to compile and submit the information we are requiring to be reported. Therefore, the total burden hours on the public per year is estimated to be a maximum of two hours.
Since nothing in the rule requires those persons who submit reports pursuant to this rule to keep copies of any records or reports submitted to us, recordkeeping costs imposed would be zero hours and zero costs.
44 U.S.C. 3506; delegation of authority at 49 CFR 1.95.
Pursuant to Section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92–463; 5 U.S.C. App. I), notice is hereby given of a meeting of the Advisory Board of the Saint Lawrence Seaway Development Corporation (SLSDC), to be held from 11:00 a.m. to 12:00 p.m. (EDT) on Thursday, May 23, 2013 at the SLSDC's Administration Building, 180 Andrews Street, Massena, New York 13662. The agenda for this meeting will be as follows: Opening Remarks; Consideration of Minutes of Past Meeting; Quarterly Report; Old and New Business; Closing Discussion; Adjournment.
Attendance at the meeting is open to the interested public but limited to the space available. With the approval of the Acting Administrator, members of the public may present oral statements at the meeting. Persons wishing further information should contact, not later than Friday, May 17, 2013, Anita K. Blackman, Senior Advisor to the Administrator, Saint Lawrence Seaway Development Corporation, Suite W32–300, 1200 New Jersey Avenue SE., Washington, DC 20590; 202–366–0091.
Any member of the public may present a written statement to the Advisory Board at any time.
Ballard Terminal Railroad Company, L.L.C. (Ballard), a Class III rail carrier, has filed a verified notice of exemption under 49 CFR 1150.41 to lease from Eastside Community Rail, LLC (ECRR) and to operate a 14.45-mile line of railroad between milepost 23.8 in Woodinville, Wash., and milepost 38.25 in Snohomish, Wash. (the Line).
Ballard has certified that its projected annual revenue as a result of this transaction will not result in Ballard's becoming a Class II or Class I rail carrier, and that its projected annual revenue will not exceed $5 million.
The transaction is expected to be consummated on or after May 2, 2013, the effective date of the exemption (30 days after the notice of exemption was filed).
If the verified notice contains false or misleading information, the exemption is void
An original and 10 copies of all pleadings, referring to Docket No. FD 35730, must be filed with the Surface Transportation Board, 395 E Street SW., Washington, DC 20423–0001. In addition, a copy of each pleading must be served on Myles L. Tobin, Fletcher & Sippel LLC, 29 North Wacker Drive, Suite 920, Chicago, IL 60606–2832.
Board decisions and notices are available on our Web site at “
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (“OFAC”) is removing the name of one (1) individual, whose property and interests in property have been blocked pursuant to Executive Order 13224 of September 23, 2001, Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten To Commit, or Support Terrorism, from the list of Specially Designated Nationals and Blocked Persons (“SDN List”).
The removal of this individual from the SDN List is effective as of April 11, 2013.
Assistant Director, Compliance Outreach & Implementation, Office of Foreign Assets Control, Department of the Treasury, Washington, DC 20220, tel.: 202/622–2490.
The SDN List and additional information concerning OFAC are available from OFAC's Web site (
On September 23, 2001, the President issued Executive Order 13224 (the “Order”) pursuant to the International Emergency Economic Powers Act, 50 U.S.C. 1701–1706, and the United Nations Participation Act of 1945, 22 U.S.C. 287c, imposing economic sanctions on persons who commit, threaten to commit, or support acts of terrorism. The President identified in the Annex to the Order various individuals and entities as subject to the economic sanctions. The Order authorizes the Secretary of the Treasury, in consultation with the Secretary of State, the Attorney General, and (pursuant to Executive Order 13284) the Secretary of the Department of Homeland Security, to designate additional persons or entities determined to meet certain criteria set forth in Executive Order 13224.
The Department of the Treasury's Office of Foreign Assets Control has determined that this individual should be removed from the SDN List.
1. UMAR, Madhat Mursi Al-Sayyid; DOB 19 Oct 1953; POB Alexandria, Egypt; nationality Egypt (individual) [SDGT].
The removal of this individual name from the SDN List is effective as of April 11, 2013. All property and interests in property of the individual that are in or hereafter come within the United States or the possession or control of United States persons are now unblocked.
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (“OFAC”) is publishing supplemental information for the names of two (2) individuals whose property and interests in property are blocked pursuant to Executive Order 13224 of September 23, 2001, “Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten To Commit, or Support Terrorism.”
The publishing of updated identification information by the Director of OFAC of these two (2) individuals in this notice, pursuant is effective on April 11, 2013.
Assistant Director, Compliance Outreach & Implementation, Office of Foreign Assets Control, Department of the Treasury, Washington, DC 20220, tel.: 202/622–2490.
This document and additional information concerning OFAC are available from OFAC's Web site (
On September 23, 2001, the President issued Executive Order 13224 (the “Order”) pursuant to the International Emergency Economic Powers Act, 50 U.S.C. 1701–1706, and the United Nations Participation Act of 1945, 22 U.S.C. 287c. In the Order, the President declared a national emergency to address grave acts of terrorism and threats of terrorism committed by foreign terrorists, including the September 11, 2001 terrorist attacks in New York, Pennsylvania, and at the Pentagon. The Order imposes economic sanctions on persons who have committed, pose a significant risk of committing, or support acts of terrorism. The President identified in the Annex to the Order, as amended by Executive Order 13268 of July 2, 2002, 13 individuals and 16 entities as subject to the economic sanctions. The Order was further amended by Executive Order 13284 of January 23, 2003, to reflect the creation of the Department of Homeland Security.
Section 1 of the Order blocks, with certain exceptions, all property and interests in property that are in or hereafter come within the United States or the possession or control of United States persons, of: (1) Foreign persons listed in the Annex to the Order; (2) foreign persons determined by the Secretary of State, in consultation with the Secretary of the Treasury, the Secretary of the Department of Homeland Security and the Attorney General, to have committed, or to pose a significant risk of committing, acts of terrorism that threaten the security of U.S. nationals or the national security, foreign policy, or economy of the United States; (3) persons determined by the Director of OFAC, in consultation with the Departments of State, Homeland
On April 11, 2013 the Director of OFAC, in consultation with the Departments of State, Homeland Security, Justice and other relevant agencies, supplemented the identification information for two (2) individuals whose property and interests in property are blocked pursuant to Executive Order 13224.
The supplementation identification information for the individuals is as follows:
1. AHMAD, Farhad Kanabi (a.k.a. HAMAWANDI, Kawa; a.k.a. OMAR ACHMED, Kaua), Lochhamer Str. 115, Munich 81477, Germany; Iraq; DOB 01 Jul 1971; POB Arbil, Iraq; nationality Iraq; Travel Document Number A0139243 (Germany) (individual) [SDGT].
2. HUSSEIN, Mazen Ali (a.k.a. SALAH MUHAMAD, Issa), Branderstrasse 28, Augsburg 86154, Germany; Hauzenberg 94051, Germany; DOB 01 Jan 1982; alt. DOB 01 Jan 1980; POB Baghdad, Iraq; nationality Iraq; Travel Document Number A0144378 (Germany) (individual) [SDGT].
The Department of Veterans Affairs (VA) gives notice under the Federal Advisory Committee Act, 5 U.S.C. App. 2, that the Special Medical Advisory Group will meet on May 1, 2013, in Room 830 at VA Central Office, 810 Vermont Avenue NW., Washington, DC, from 8:30 a.m. to 3 p.m. The meeting is open to the public.
The purpose of the Group is to advise the Secretary of Veterans Affairs and the Under Secretary for Health on the care and treatment of disabled Veterans, and other matters pertinent to the Department's Veterans Health Administration (VHA).
The agenda for the meeting will include discussions on VA and Department of Defense Collaboration; the Executive Order to Improve Access to Mental Health Services for Veterans, Service Members and Their Families; VA's Approach to End of Life Care; an Update on the National Academic Affiliations Council; and an annual ethics briefing for Committee members.
No time will be allocated for receiving oral presentations from the public. However, members of the public may submit written statements for review by the Committee to Jennifer Adams, Department of Veterans Affairs, Office of the Principal Deputy Under Secretary for Health (10A), Veterans Health Administration, 810 Vermont Avenue NW., Washington, DC 20420, or by email at
By Direction of the Secretary:
The Department of Veterans Affairs (VA) gives notice under the Federal Advisory Committee Act, 5 U.S.C. App. 2, that a meeting of the Advisory Committee on Cemeteries and Memorials will be held on May 7–8, 2013, in Winchester B Meeting Room at the Holiday Inn Saint Louis-South I–55, 4234 Butler Hill, St. Louis, MO, from 8:30 a.m. to 4 p.m. The meeting is open to the public.
The purpose of the Committee is to advise the Secretary of Veterans Affairs on the administration of national cemeteries, soldiers' lots and plots, the selection of new national cemetery sites, the erection of appropriate memorials, and the adequacy of Federal burial benefits.
On May 7, the Committee will receive updates on National Cemetery Administrations issues. On the morning of May 8, the Committee will tour the Jefferson Barracks National Cemetery, 2900 Sheridan Road, St. Louis, MO. In the afternoon, the Committee will reconvene at the Conference Center and discuss Committee recommendations, future meeting sites, and potential agenda topics at future meetings.
Time will be allocated for receiving public comments at 1 p.m. on both days. Public comments will be limited to three minutes each. Individuals wishing to make oral statements before the Committee will be accommodated on a first-come, first-served basis. Individuals who speak are invited to submit 1–2 page summaries of their comments at the time of the meeting for inclusion in the official meeting record.
Members of the public may direct questions or submit written statements for review by the Committee in advance of the meeting to Mr. Michael Nacincik, Designated Federal Officer, Department of Veterans Affairs, National Cemetery Administration (43A2), 810 Vermont Avenue NW., Washington, DC 20420, or by email at
By Direction of the Secretary.
The Department of Veterans Affairs (VA) gives notice under the Federal Advisory Committee Act, 5 U.S.C. App. 2, that the Advisory Committee on Disability Compensation will meet on April 25–26, 2013, in Room 800 at the
The purpose of the Committee is to advise the Secretary of Veterans Affairs on the maintenance and periodic readjustment of the VA Schedule for Rating Disabilities. The Committee is to assemble and review relevant information relating to the nature and character of disabilities arising during service in the Armed Forces, provide an ongoing assessment of the effectiveness of the rating schedule, and give advice on the most appropriate means of responding to the needs of Veterans relating to disability compensation.
The Committee will receive briefings on issues related to compensation for Veterans with service-connected disabilities and other VA benefits programs. Time will be allocated for receiving public comments in the afternoon. Public comments will be limited to three minutes each. Individuals wishing to make oral statements before the Committee will be accommodated on a first-come, first-served basis. Individuals who speak are invited to submit 1–2 page summaries of their comments at the time of the meeting for inclusion in the official meeting record.
The public may submit written statements for the Committee's review to Nancy Copeland, Acting Designated Federal Officer, Department of Veterans Affairs, Veterans Benefits Administration, Compensation Service, Regulation Staff (211D), 810 Vermont Avenue NW., Washington, DC 20420 or email at
By Direction of the Secretary:
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Final rule.
The Energy Policy and Conservation Act of 1975 (EPCA), as amended, prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including distribution transformers. EPCA also requires the U.S. Department of Energy (DOE) to determine whether more-stringent standards would be technologically feasible and economically justified, and would save a significant amount of energy. In this final rule, DOE is adopting more-stringent energy conservation standards for distribution transformers. It has determined that the amended energy conservation standards for this equipment would result in significant conservation of energy, and are technologically feasible and economically justified.
The effective date of this rule is June 17, 2013. Compliance with the amended standards established for distribution transformers in this final rule is required as of January 1, 2016.
The docket for this rulemaking is available for review at
A link to the docket Web page can be found at:
For further information on how to review the docket, contact Ms. Brenda Edwards at (202) 586–2945 or by email:
Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the Act), Public Law 94–163 (42 U.S.C. 6291–6309, as codified), established the Energy Conservation Program for Consumer Products Other Than Automobiles. Part C of Title III of EPCA (42 U.S.C. 6311–6317) established a similar program for “Certain Industrial Equipment,” including distribution transformers.
For the reasons discussed in this preamble, particularly in Section V, DOE is adopting TSL 1 for liquid-immersed distribution transformers. DOE acknowledges the input of various stakeholders in support of a more stringent energy conservation standard for liquid-immersed distribution transformers. DOE notes that the potential for significant disruption in the steel supply market at higher efficiency levels was a key element in adopting TSL 1 in this rulemaking. DOE will monitor the steel and liquid-immersed distribution transformer markets and by no later than 2016, determine whether interim changes to market conditions, particularly the supply chain for amorphous steel, justify re-evaluating the efficiency standards adopted in today's rulemaking.
Although DOE proposed TSL 1 for low-voltage dry-type distribution transformers, DOE is adopting in this final rule TSL 2 for such transformers for the reasons discussed in greater detail in Section IV.I.5.B. DOE acknowledges that various stakeholders
Table I.8 summarizes DOE's evaluation of the economic impacts of today's standards on customers who purchase distribution transformers, as measured by the average life-cycle cost (LCC) savings and the median payback period (PBP). DOE measures the impacts of standards relative to a base case that reflects likely trends in the distribution transformer market in the absence of amended standards. The base case predominantly consists of products at the baseline efficiency levels evaluated for each representative unit, which correspond to the existing energy conservation standards for distribution transformers. (Throughout this document, “distribution transformers” are also referred to as simply “transformers.”)
The industry net present value (INPV) is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2012 to 2045). Using a real discount rate of 7.4 percent for liquid-immersed distribution transformers, 9 percent for medium-voltage dry-type distribution transformers, and 11.1 percent for low-voltage dry-type distribution transformers, DOE estimates that the INPV for manufacturers of liquid-immersed, medium-voltage dry-type, and low-voltage dry-type distribution transformers is $575.1 million, $68.7 million, and $237.6 million, respectively, in 2011$. Under the standards of today's rule, DOE expects that manufacturers of liquid-immersed units may lose as much as 8.4 percent of their INPV, which is approximately $48.2 million; medium-voltage manufacturers may lose as much as 4.2 percent of their INPV, which is approximately $2.9 million; and low-voltage manufacturers may lose as much as 4.7 percent of their INPV, which is approximately $11.1 million. Additionally, based on DOE's interviews with the manufacturers of distribution transformers, DOE does not expect any plant closings or significant loss of employment.
DOE's analyses indicate that today's standards would save a significant amount of energy. The lifetime savings for equipment purchased in the 30-year period that begins in the year of compliance with amended standards (2016–2045) amounts to 3.63 quads.
The cumulative net present value (NPV) of total customer costs and savings of today's standards for distribution transformers, in 2011$, ranges from $3.4 billion (at a 7-percent discount rate) to $12.9 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased equipment costs for equipment purchased in 2016–2045, discounted to 2012.
In addition, today's standards would have significant environmental benefits. The energy savings would result in cumulative emission reductions of 264.7 million metric tons (Mt)
The value of the CO
Table I.9 summarizes the national economic costs and benefits expected to result from today's standards for distribution transformers.
The benefits and costs of today's standards, for equipment sold in 2016–2045, can also be expressed in terms of annualized values. The annualized monetary values are the sum of: (1) The annualized national economic value of the benefits from customer operation of equipment that meets today's standards (consisting primarily of operating cost savings from using less energy, minus increases in equipment purchase and installation costs, which is another way of representing customer NPV), and (2) the annualized monetary value of the benefits of emission reductions, including CO
Although combining the values of operating cost savings and CO
Estimates of annualized benefits and costs of today's standards are shown in Table I.10. The results under the primary estimate are as follows. (All monetary values below are expressed in 2011$.) Using a 7-percent discount rate for benefits and costs (other than CO
Based on the analyses culminating in this final rule, DOE found the benefits to the nation of the standards (energy savings, consumer LCC savings, positive NPV of customer benefit, and emission reductions) outweigh the burdens (loss of INPV and LCC increases for some users of this equipment). DOE has concluded that the standards in today's final rule represent the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in significant conservation of energy.
The following section briefly discusses the statutory authority underlying today's final rule, as well as some of the relevant historical background related to the establishment of today's amended standards.
Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the Act), Public Law 94–163 (42 U.S.C. 6291–6309, as codified), established the Energy Conservation Program for “Consumer Products Other Than Automobiles.” Part C of Title III of EPCA (42 U.S.C. 6311–6317) established a similar program for “Certain Industrial Equipment,” including distribution transformers.
For those distribution transformers for which DOE determines that energy conservation standards are warranted, the DOE test procedures must be the “Standard Test Method for Measuring the Energy Consumption of Distribution Transformers” prescribed by the National Electrical Manufacturers Association (NEMA TP 2–1998), subject to review and revision by the Secretary of Energy in accordance with certain criteria and conditions. (42 U.S.C. 6293(b)(10), 6314(a)(2)–(3) and 6317(a)(1)) Manufacturers of such covered equipment must use the prescribed DOE test procedure as the basis for certifying to DOE that their equipment complies with the applicable energy conservation standards adopted under EPCA and when making representations to the public regarding the energy use or efficiency of those types of equipment. (42 U.S.C. 6314(d)) The DOE test procedures for distribution transformers appear at title 10 of the Code of Federal Regulations (CFR) part 431, subpart K, appendix A.
DOE is required to follow certain statutory criteria for prescribing amended standards for covered equipment. As indicated above, any amended standard for covered equipment must be designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a)) Furthermore, DOE may not adopt any standard that would not result in the significant conservation of energy. (42 U.S.C. 6295(o)(3) and 6316(a)) Moreover, DOE may not prescribe a standard: (1) For certain equipment, including distribution transformers, if no test procedure has been established for the equipment, or (2) if DOE determines by rule that the amended standard is not technologically feasible or economically justified. (42 U.S.C. 6295(o)(3) and 6316(a)) In deciding whether an amended standard is economically justified, DOE must determine whether the benefits of the standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a)) DOE must make this determination after receiving comments on the proposed standard, and by considering, to the greatest extent practicable, the following seven factors:
1. The economic impact of the standard on manufacturers and customers of the equipment subject to the standard;
2. The savings in operating costs throughout the estimated average life of the covered equipment in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products that are likely to result from the imposition of the standard;
3. The total projected amount of energy, or as applicable, water, savings likely to result directly from the imposition of the standard;
4. Any lessening of the utility or the performance of the covered equipment likely to result from the imposition of the standard;
5. The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the imposition of the standard;
6. The need for national energy and water conservation; and
7. Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a))
EPCA, as codified, also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. (42 U.S.C. 6295(o)(1) and 6316(a)) Also, the Secretary may not prescribe an amended or new standard if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States of any covered product type (or class) of performance characteristics (including reliability, features, sizes, capacities, and volumes) that are substantially the same as those generally available in the United States. (42 U.S.C. 6295(o)(4) and 6316(a))
Further, EPCA, as codified, establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the customer of purchasing equipment complying with an energy conservation standard level will be less than three times the value of the energy savings during the first year that the customer will receive as a result of the standard, as calculated under the applicable test procedure. See 42 U.S.C. 6295(o)(2)(B)(iii) and 6316(a).
Additionally, 42 U.S.C. 6295(q)(1), as applied to covered equipment under 42 U.S.C. 6316(a), specifies requirements when promulgating a standard for a type or class of covered equipment that has two or more subcategories. DOE must specify a different standard level than that which applies generally to such type or class of equipment for any group of covered equipment that has the same function or intended use if DOE determines that equipment within such group: (A) Consumes a different kind of energy from that consumed by other covered equipment within such type (or class); or (B) has a capacity or other performance-related feature which other equipment within such type (or class) does not have and such feature justifies a higher or lower standard. (42 U.S.C. 6295(q)(1) and 6316(a)) In determining whether a performance-related feature justifies a different standard for a group of equipment, DOE must consider such factors as the utility to the customer of such a feature and other factors DOE deems appropriate.
Federal energy conservation requirements generally supersede State laws or regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6297(a)–(c) and 6316(a)) DOE may, however, grant waivers of Federal preemption for particular State laws or regulations, in accordance with the procedures and other provisions set forth under 42 U.S.C. 6297(d)).
DOE has also reviewed this regulation pursuant to Executive Order (EO) 13563, issued on January 18, 2011 (76 FR 3281, January 21, 2011). EO 13563 is supplemental to and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in EO 12866. To the extent permitted by law, agencies are required by EO 13563 to: (1) Propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing
DOE emphasizes as well that EO 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, the Office of Information and Regulatory Affairs has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, DOE believes that today's final rule is consistent with these principles, including the requirement that, to the extent permitted by law, benefits justify costs and that net benefits are maximized. Consistent with EO 13563, and the range of impacts analyzed in this rulemaking, the energy efficiency standard adopted herein by DOE achieves maximum net benefits.
On August 8, 2005, EPACT 2005 amended EPCA to establish energy conservation standards for low-voltage dry-type distribution transformers (LVDTs).
DOE incorporated these standards into its regulations, along with the standards for several other types of products and equipment, in a final rule published on October 18, 2005. 70 FR 60407, 60416–60417. These standards appear at 10 CFR 431.196(a).
On October 12, 2007, DOE published a final rule that established energy conservation standards for liquid-immersed distribution transformers and medium-voltage dry-type distribution transformers, which are shown in Table II.2 and Table II.3, respectively. 72 FR 58190, 58239–40. These standards are codified at 10 CFR 431.196(b) and (c). See Tables I.5 and I.7 above for today's amended liquid-immersed and medium-voltage dry-type (MVDT) standards.
In a notice published on October 22, 1997 (62 FR 54809), DOE stated that it had determined that energy conservation standards were warranted for electric distribution transformers, relying in part on two reports by DOE's Oak Ridge National Laboratory (ORNL). In 2000, DOE issued and took comment on its Framework Document for Distribution Transformer Energy Conservation Standards Rulemaking, describing its proposed approach for developing standards for distribution transformers, and held a public meeting to discuss the framework document. The document is available at:
On July 29, 2004, DOE published an advance notice of proposed rulemaking (ANOPR) for distribution transformer standards.
On April 27, 2006, DOE published its Final Rule on Test Procedures for Distribution Transformers. The rule: (1) established the procedure for sampling and testing distribution transformers so that manufacturers can make representations as to their efficiency, as well as establish that they comply with Federal standards; and (2) outlined the procedure the Department of Energy would follow should it initiate an enforcement action against a manufacturer. 71 FR 24972 (codified at 10 CFR 431.198).
On August 4, 2006, DOE published a NOPR in which it proposed energy conservation standards for distribution transformers (the 2006 NOPR). 71 FR 44355. Concurrently, DOE also issued a technical support document (TSD) that incorporated the analyses it had performed for the proposed rule.
Some commenters asserted that DOE's proposed standards might adversely affect replacement of distribution transformers in certain space-constrained (e.g., vault) installations. In response, DOE issued a notice of data availability and request for comments on this and another issue. 72 FR 6186 (February 9, 2007) (the NODA). In the NODA, DOE sought comment on whether it should include in the LCC analysis potential costs related to size constraints of distribution transformers installed in vaults, and requested comments on linking energy efficiency levels for three-phase liquid-immersed units with those of single-phase units. 72 FR 6189. Based on comments on the 2006 NOPR and the NODA, DOE created new TSLs to address the treatment of three-phase units and single-phase units and incorporated increased installation costs for pole-mounted and vault transformers. In October 2007, DOE published a final rule that created the current energy conservation standards for liquid-immersed and medium-voltage dry-type distribution transformers. 72 FR 58190 (October 12, 2007) (the 2007 Final Rule) (codified at 10 CFR 431.196(b)–(c)). The preamble to the rule included additional, detailed background information on the history of that rulemaking. 72 FR 58194–96.
After the publication of the 2007 final rule, certain parties filed petitions for review in the United States Courts of Appeals for the Second and Ninth Circuits, challenging the rule. Several additional parties were permitted to intervene in support of those petitions. (All of these parties are referred to below collectively as “petitioners.”) The petitioners alleged that, in developing its energy conservation standards for distribution transformers, DOE did not comply with certain applicable provisions of EPCA and of the National Environmental Policy Act (NEPA), as amended (42 U.S.C. 4321
On March 2, 2011, DOE published in the
On July 29, 2011, DOE published in the
The ERAC subcommittee for medium-voltage liquid-immersed, and dry-type distribution transformers consisted of representatives of parties, listed below, having a defined stake in the outcome of the proposed standards and included:
The ERAC subcommittee for medium-voltage liquid-immersed, and dry-type distribution transformers held meetings in 2011 on September 15 through 16, October 12 through 13, November 8 through 9, and November 30 through December 1; the ERAC subcommittee also held public webinars on November 17 and December 14. The meetings were open to the public. During the September 15, 2011, meeting, the subcommittee agreed to its rules of procedure, ratified its schedule of the remaining meetings, and defined the procedural meaning of consensus. The subcommittee defined consensus as unanimous agreement from all present subcommittee members. Subcommittee members were allowed to abstain from voting for an efficiency level; in such cases their votes counted neither toward nor against the consensus.
DOE presented its draft engineering, life-cycle cost, and national impacts analysis and results. During the meetings of October 12 through 13, 2011, DOE presented its revised analysis and heard from subcommittee members on a number of topics. During the meetings on November 8 through 9, 2011, DOE presented its revised analysis, including life-cycle cost sensitivities based on excluding ZDMH and amorphous steel as core materials. During the meetings on November 30 through December 1, 2011, DOE presented its revised analysis based on 2011 core-material prices.
At the conclusion of the final meeting, subcommittee members presented their efficiency level recommendations. For medium-voltage liquid-immersed distribution transformers, the energy efficiency Advocates, represented by the Appliance Standards Awareness Project (ASAP), recommended efficiency level (also referred to as “EL”) 2 for all design lines (also referred to as “DLs”). The National Electrical Manufacturers Association (NEMA) and AK Steel recommended EL 1 for all DLs except for DL 2, for which no change from the current standard was recommended. Edison Electric Institute (EEI) and ATI Allegheny Ludlum recommended EL1 for DLs 1, 3, and 4 and no change from the current standard or a proposed standard of less than EL 1 for DLs 2 and 5. Therefore, the subcommittee did not arrive at consensus regarding proposed standard levels for medium-voltage liquid-immersed distribution transformers.
For medium-voltage dry-type distribution transformers, the subcommittee arrived at consensus and recommended a proposed standard of EL2 for DLs 11 and 12, from which the proposed standards for DLs 9, 10, 13A, and 13B would be scaled. Transcripts of the all subcommittee meetings (for all transformer types) and all data and materials presented at the subcommittee meetings are available via a link under the DOE Web site at:
The ERAC subcommittee held meetings in 2011 on September 28, October 13–14, November 9, and December 1–2 for low-voltage distribution transformers. The ERAC subcommittee also held webinars on November 21, 2011, and December 20, 2011. The meetings were open to the public. During the September 28, 2011, meeting, the subcommittee agreed to its
The ERAC subcommittee for low-voltage distribution transformers consisted of representatives of parties having a defined stake in the outcome of the proposed standards and included:
DOE presented its draft engineering, life-cycle cost and national impacts analysis and results. During the meeting of October 14, 2011, DOE presented its revised analysis and heard from subcommittee members on various topics. During the meeting of November 9, 2011, DOE presented its revised analysis. During the meeting of December 1, 2011, DOE presented its revised analysis based on 2011 core-material prices.
At the conclusion of the final meeting, subcommittee members presented their energy efficiency level recommendations. For low-voltage dry-type distribution transformers, the Advocates, represented by ASAP, recommended EL4 for all DLs; NEMA recommended EL 2 for DLs 7 and 8, and no change from the current standard for DL 6. EEI, AK Steel and ATI Allegheny Ludlum recommended EL 1 for DLs 7 and 8, and no change from the current standard for DL 6. The subcommittee did not arrive at consensus regarding a proposed standard for low-voltage dry-type distribution transformers.
DOE published a NOPR on February 10, 2012, which proposed amended standards for all three transformer types. 77 FR 7282. Medium-voltage dry-type distribution transformers were proposed at the negotiating committee's consensus level. Liquid-immersed distribution transformers were proposed at TSL 1. Low-voltage dry-type distribution transformers were proposed at TSL 1. In the NOPR, DOE sought comment on a number of issues related to the rulemaking.
Following publication of the NOPR, DOE received several comments expressing a desire to see some of the NOPR suggestions extended and analyzed for liquid-immersed distribution transformers. In response, DOE generated a supplementary NOPR analysis with three additional TSLs. The three TSLs presented were based on possible new equipment classes for pole-mounted distribution transformers, network/vault-based distribution transformers, and those with high basic impulse level (BIL) ratings. On June 4, 2012 DOE published a notice announcing the availability of this supplementary analysis
DOE published its test procedure for distribution transformers in the
As detailed below, in today's notice, DOE determines that an amended test procedure is not necessary because the 2006 test procedure is reasonably designed to produce test results that reflect energy efficiency and energy use, and an amended test procedure that more precisely measures energy efficiency and energy use for every possible distribution transformer configuration would be unduly burdensome to conduct.
Several parties commented on the test procedure for distribution transformers. The California Investor Owned Utilities (CA IOUs) commented that DOE should not modify the test procedure. (CA IOUs, No. 189 at p. 1) Today's rule contains no test procedure amendments, but the rule does clarify the test procedure's application in response to comments. DOE may revisit the issue of test procedures in a future proceeding.
NEMA commented that because of variability in process, materials, and testing, manufacturers must “overdesign” transformers in order to have confidence that their products will meet standards. (NEMA, No. 170 at p. 3) DOE notes that its compliance procedures already contain allowances for statistical variation as a result of measurement, laboratory, and testing procedure variability. Manufacturers are also required to take certification sampling plans and tolerances into account when developing their certified ratings after testing a sample of minimum units from the production of a basic model. The represented efficiency equation essentially allows a manufacturer to “represent” a basic model of distribution transformer as having achieved a higher efficiency than calculated through testing the minimum sample for certification. DOE is not adopting any modifications to its certification or enforcement sampling procedures in this final rule, but it may further address them in a separate proceeding at a later date if it finds such practices to be overly strict or generous.
Additionally, Schneider Electric commented that DOE's test procedure is inadequate or ambiguous in several areas, including test environment drafts, ambient method internal temperatures, test environment ambient temperature variation, ambient method test delays,
Finally, DOE's present sampling plans require a minimum number of units be tested in order to calculate the represented efficiency of a basic model. (10 CFR 429.47 (a)). Prolec-GE commented that DOE's compliance protocols allow too small a statistical variation, particularly because silicon steel sees a greater variation in losses than does the amorphous variety. (Prolec-GE, No. 177 at p. 17) To the extent Prolec-GE is concerned about the variability in their production, DOE notes that the statistical sampling plans allow for manufacturers to increase the sample size, which should help better characterize the variability association with the production. DOE's existing sampling plans are a balance between manufacturing burden associated with testing and accurately characterizing the efficiency of a given basic model based on a sample of the production. While DOE is not adopting any changes to its existing sampling plans in today's final rule, DOE welcomes data showing the production variability for different types and efficiencies of distribution transformers to help better inform any changes that may be considered in a separate and future proceeding.
The current test procedure is not specific regarding which kVA rating should be used to assess compliance in the case of distribution transformers that have more than one rating. Though less common in distribution transformers than in other types of transformers (e.g., “power” or “substation” transformers), active cooling measures such as fans or pumps are sometimes used to aid cooling. Greater heat dissipation capacity means that the transformer can be safely operated at higher loading levels for longer periods of time. Active cooling components generally carry much shorter lifetimes than the transformer itself, however, and the failure of any cooling component would expose the transformer at-large to premature failure due to elevated temperatures. Accordingly, distribution transformers rarely contain such components and, when they do, rarely make use of them except in occasional overload situations. As a result, they play little role in the design of the transformer or in a transformer's ability to operate efficiently even when equipped.
Apart from ratings corresponding to active cooling, transformers may also carry additional ratings (i.e., above the “base rating”) corresponding to passive cooling and reflecting different temperature rises. A transformer would be rated for higher kVA if allowed to rise to a greater temperature and, by extension, dissipate more energy.
DOE sought comment on whether the test procedure needs greater specificity with respect to multiple kVA ratings. No party argued that distribution transformers should comply with standards at any ratings corresponding to active cooling, for the reasons discussed above. Four manufacturers (Howard Industries, Cooper Power Systems, Prolec-GE, and Schneider Electric), one trade organization (NEMA), and one utility (Progress Energy) all commented that compliance should be based exclusively on a transformer's “base” rating, or the rating that corresponds to the lowest temperature rise. (Prolec-GE, No. 177 at p. 6; Schneider, No. 180 at p. 2; PEMCO, No. 183 at p. 2; PE, No. 192 at p. 3; HI, No. 151 at p. 12; NEMA, No. 170 at pp. 6–7) ABB argued that compliance should be based on a transformer's base rating and on any others (if any) corresponding to passive cooling. (ABB, No. 158 at pp. 2–4) HVOLT commented that the term “passive cooling” may not be sufficient to clarify DOE's intent because some transformers have more than one rating which may be achieved with passive cooling. (HVOLT, No. 146 at p. 49)
Though prevalent in certain types of larger transformers, active cooling is not a significant feature in the design or operation of distribution transformers. Distribution transformers are seldom equipped with active cooling features or designed to make use of them. Additionally, units which are equipped with such features are rarely operated using them. As a result, active cooling features bear little influence on transformer efficiency and are not appropriate for use in measuring energy efficiency. Similarly, transformers with more than one rating corresponding to passive cooling will experience reduced equipment lifetime when operated at those high ratings and are therefore best evaluated at their lowest, “base” rating. DOE clarifies today that manufacturers should use a transformer's base kVA rating to assess compliance. For distribution transformers with more than one kVA rating, base kVA rating means the kVA rating that corresponds to the lowest temperature rise that actively removes heat from the distribution transformer without engagement of any fans, pumps, or other equipment. It is the base kVA rating and the base kVA rating only, which manufacturers should base their certified ratings on and on which DOE will assess compliance. In no case should a distribution transformer be certified using any kVA rating corresponding to heat removal or enhanced convection by auxiliary equipment.
Distribution transformers may be built such that different winding configurations carry different BIL ratings. In the past, MVDT transformers were placed into equipment classes by BIL rating (among other criteria) and the question arose of which rating (if there were more than one) should be used to assess compliance. Currently, DOE requires distribution transformers to comply with standards using the BIL rating of the winding configuration that produces the greatest losses. (10 CFR part 431, subpart K, appendix A)
BIL rating offers additional utility in the form of increased resistance to large voltage transients arising, for example, from lightning strikes, but requires some design compromises that affect efficiency, primarily with respect to winding clearances. A transformer rated for a given BIL must be designed as such, even if the windings may be reconfigured such that they carry a lower rating. For this reason, Progress Energy, PEMCO, NEMA, Cooper Power Systems, Power Partners, and Howard Industries all commented that transformers with multiple BIL ratings should comply only at the highest BIL for which they are rated. (HI, No. 151 at p. 12; Power Partners, No. 155 at p. 1–2; Cooper, No. 165 at p. 2; NEMA, No. 170 at p. 7; Prolec-GE, No. 177 at p. 6; PEMCO, No. 183 at p. 2; PE, No. 192 at p. 3) ABB commented that transformers should meet the efficiency levels of all of its rated BILs, because there is no way to know in advance how a transformer will be operated over its lifetime. (ABB, No. 158 at p. 4)
Although DOE agrees there is no way to be sure how a distribution transformer will be operated over its lifetime, it does not believe multiple BIL ratings currently present an energy conservation standards circumvention
DOE clarifies that transformers may be certified at any BIL for which they are rated, including the highest BIL ratings. This does nothing to change DOE's requirement that distribution transformers comply in the configuration that produces the greatest losses, however, even if that configuration itself does not carry the highest BIL rating. For example, a MVDT distribution transformer may have two winding configurations, respectively BIL rated at 60 kV and 125 kV. Although the distribution transformer must meet only the 125 kV standards, it may produce greater losses (and thus need to be certified) in the 60 kV configuration.
Currently, DOE requires manufacturers to comply with energy conservation standards while the distribution transformer's primary windings (“primaries”) are in the configuration that produces the highest losses. (10 CFR part 431, subpart K, appendix A)
DOE understands that, in contrast to the secondary windings, reconfigurable primaries typically exhibit a larger variation in efficiency between series and primary connections. Such transformers are often purchased with the intent of upgrading the local power grid to a higher operating voltage and lowered overall system losses.
Several parties commented on the matter of primary winding configurations in response to the NOPR. Kentucky Association of Electric Cooperatives (KAEC), Cooper Power Systems, NEMA, and Progress Energy commented that it is least burdensome for manufacturers if they can report losses in the same configuration in which the transformers are shipped, which by Institute of Electrical and Electronics Engineers (IEEE) standards must be the series configuration. (KAEC, No. 149 at p. 2; NEMA, No. 170 at p. 6; PE, No. 192 at p. 10; PE, No. 192 at p. 2; Prolec-GE, No. 177 at p. 5; Schneider, No. 180 at p. 2; Schneider, No. 180 at p. 8; Cooper Power Systems, No. 222 at p. 3) Howard Industries and Prolec-GE commented that manufacturers should be allowed to test distribution transformers with their primaries in any configuration. (HI, No. 151 at p. 12; Prolec-GE, No. 177 at p. 5) Utilities Baltimore Gas and Electric and Commonwealth Edison supported testing in the configuration in which the transformer will ultimately be used. (BG&E, No. 182 at p. 2; ComEd, No. 184 at p. 2)
ABB submitted comments and data explaining that the ratios of the losses of different winding positions varied considerably and, as a result, that there was no reliable way to predict which configuration would carry the lowest losses. ABB and the California IOUs supported maintaining the test procedure's current requirements. (ABB, No. 158 at p. 2; CA IOUs, No. 189 at pp. 1–2)
DOE is concerned that the primary winding configuration can have a significant impact on energy consumption and that by relaxing the restriction of compliance in the configuration producing the highest losses, any forecasted energy savings may be diminished. DOE is not modifying any test procedure requirements in today's rule, but may reexamine the topic in a dedicated test procedure rulemaking in the future.
DOE understands that some distribution transformers may be shipped with reconfigurable secondary windings, and that certain configurations may have different efficiencies. Currently, DOE requires distribution transformers to be tested in the configuration that exhibits the highest losses. Whereas the IEEE standard
Several parties commented on the matter of reconfigurable secondary windings. Cooper Power Systems, KAEC, NEMA, Progress Energy, and Schneider Electric supported conducting testing with windings in series, as is the IEEE convention and as would produce the highest voltage. (Cooper, No. 165 at pp. 1–2, 6 No. 222 at p. 3; HI, No. 151 at p. 12; KAEC, No. 149 at p. 2; NEMA, No. 170 at p. 6; PE, No. 192 at p. 10; PE, No. 192 at p. 2; Schneider, No. 180 at p. 2; Schneider, No. 180 at p. 8)
Power Partners and Prolec-GE commented that testing should be permitted in any winding configuration at the discretion of the manufacturer. (Power Partners, No. 155 at p. 1; Prolec-GE, No. 177 at pp. 3–4)
Additionally, ABB and the California IOUs commented that there was no way of knowing which position would produce the greatest losses and, therefore, the test procedure should remain unchanged with respect to winding configuration requirements. (ABB, No. 158 at p. 2; CA IOUs, No. 189 at p. 1–2)
DOE is concerned that secondary windings may have significantly different losses in various configurations and that, furthermore, there is no reliable way to predict in which configuration the transformer will be operated over the majority of its lifetime. Just as with dual/multiple primary windings, changing the requirement of testing in the configuration producing the highest losses, may diminish forecasted energy savings. As a result, DOE is not modifying any test procedure requirements in today's rule, but may reexamine the topic in a dedicated test procedure rulemaking in the future.
Currently, DOE requires that both liquid-immersed and medium-voltage dry-type distribution transformers comply with standards at 50 percent loading and that low-voltage dry-type distribution transformers comply at 35 percent loading. DOE wishes to clarify that the loading discussed herein pertains only to that which manufacturers must use to test their equipment. DOE's economic analysis uses loading distributions that attempt to reflect the most recent understanding of the United States electrical grid. DOE does not believe that all (or the average of all) customers utilize transformers at the required test procedure loading values.
Several parties commented on the appropriateness of these test loading values. ABB, ComEd, Cooper, EEI, Howard, KAEC, NEMA, NRECA, PEMCO, Prolec-GE, and Schneider all commented that the values were appropriate and should continue to be used. (ABB, No. 158 at p. 5; ComEd, No. 184 at p. 2; Cooper, No. 165 at p. 2; EEI, No. 185 at p. 4; HI, No. 151 at p. 12; KAEC, No. 149 at p. 3; NEMA, No. 170 at p. 12; NRECA, No. 172 at p. 4; PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7; Schneider, No. 180 at p. 3)
Progress Energy commented that it believed the current values suffice for the present but that DOE should further explore the topic in the future. (PE, No. 192 at p. 3) BG&E commented that utilities had oversized transformers in the past due to lack of ability to accurately monitor loading and that loading will increase in the future. (BG&E, No. 182 at p. 3) Finally, MGLW and the Copper Development
DOE understands that distribution transformers experience a range of loading levels when installed in the field. DOE understands that the majority of stakeholders, including manufacturers and utilities, support retention of the current testing requirements and DOE determined that its existing test procedure provides results that are representative of the performance of distribution transformers in normal use. Although DOE may examine the topic of potential loading points in a dedicated test procedure rulemaking in the future, at this time, DOE does not believe that the potential improvement in testing precision outweighs the complexity and the burden of requiring testing at different loadings depending on each individual transformer's characteristics.
In each standards rulemaking, DOE conducts a screening analysis based on information it has gathered on all current technology options and prototype designs that could improve the efficiency of the products that are the subject of the rulemaking. As the first step in such analysis, DOE develops a list of technology options for consideration in consultation with manufacturers, design engineers, and other interested parties. DOE then determines which of these means for improving efficiency are technologically feasible. DOE considers technologies incorporated in commercially available products or in working prototypes to be technologically feasible. 10 CFR 430, subpart C, appendix A, section 4(a)(4)(i) There are distribution transformers available at all of the energy efficiency levels considered in today's final rule. Therefore, DOE believes all of the energy efficiency levels adopted by today's final rulemaking are technologically feasible.
Once DOE has determined that particular technology options are technologically feasible, it further evaluates each of them in light of the following additional screening criteria: (1) Practicability to manufacture, install, or service; (2) adverse impacts on product utility or availability; and (3) adverse impacts on health or safety. For further details on the screening analysis for this rulemaking, see chapter 4 of the final rule TSD.
When DOE considers an amended standard for a type or class of covered equipment, it must determine the maximum improvement in energy efficiency or maximum reduction in energy use that is technologically feasible for that equipment. (42 U.S.C. 6295(p)(1); 42 U.S.C. 6316(a)) While developing the energy conservation standards for liquid-immersed and medium-voltage dry-type distribution transformers that were codified under 10 CFR 431.196, DOE determined the maximum technologically feasible (max-tech) energy efficiency level through its engineering analysis. The max-tech design incorporates the most efficient materials, such as core steels and winding materials, and applied design parameters that create designs at the highest efficiencies achievable at the time. 71 FR 44362 (August 4, 2006) and 72 FR 58196 (October 12, 2007). DOE used those designs to establish max-tech levels for its LCC analysis, then scaled them to other kVA ratings within a given design line to establish max-tech efficiencies for all the distribution transformer kVA ratings. For today's rule, DOE determined max-tech in exactly the same manner.
For each TSL, DOE projected energy savings from the products that are the subject of this rulemaking purchased in the 30-year period that begins in the year of compliance with amended standards (2016–2045). The savings are measured over the entire lifetime of products purchased in the 30-year period.
DOE used its national impact analysis (NIA) spreadsheet model to estimate energy savings from amended standards for the products that are the subject of this rulemaking. The NIA spreadsheet model calculates energy savings in site electricity, which is the energy directly consumed by transformers at the locations where they are used. DOE reports national energy savings on an annual basis in terms of the primary energy savings, which is the savings in the energy that is used to generate and transmit the site electricity. To convert site electricity to primary energy, DOE derived annual conversion factors from the model used to prepare the Energy Information Administration's (EIA)
As noted above, 42 U.S.C. 6295(o)(3)(B) prevents DOE from adopting a standard for covered equipment if such a standard would not result in significant energy savings. While EPCA does not define the term “significant,” the U.S. Court of Appeals for the District of Columbia, in
As noted previously, EPCA requires DOE to evaluate seven factors to determine whether a potential energy conservation standard is economically justified. (42 U.S.C. 6295(o)(2)(B)(i)) The following sections describe how DOE has addressed each of the seven factors in this rulemaking.
In determining the impacts of an amended standard on manufacturers, DOE first determines the quantitative impacts using an annual cash-flow approach. This includes both a short-term assessment, based on the cost and capital requirements during the period between the issuance of a regulation and when entities must comply with the regulation, and a long-term assessment for a 30-year analysis period. The
For individual customers, measures of economic impact include the changes in LCC and the PBP associated with new or amended standards. The LCC, which is separately specified in EPCA as one of the seven factors to be considered in determining the economic justification for a new or amended standard (42 U.S.C. 6295(o)(2)(B)(i)(II)), is discussed in the following section. For customers in the aggregate, DOE also calculates the national NPV of the economic impacts on customers over the forecast period applicable to a particular rulemaking.
The LCC is the sum of the purchase price of a type of equipment (including its installation) and the operating expense (including energy and maintenance and repair expenditures) discounted over the lifetime of the equipment. The LCC savings for the considered energy efficiency levels are calculated relative to a base case that reflects likely trends in the absence of amended standards. The LCC analysis requires a variety of inputs, such as equipment prices, equipment energy consumption, energy prices, maintenance and repair costs, equipment lifetime, and customer discount rates. DOE assumed in its analysis that customers will purchase the considered equipment in 2016.
To account for uncertainty and variability in specific inputs, such as equipment lifetime and discount rate, DOE uses a distribution of values with probabilities attached to each value. A distinct advantage of this approach is that DOE can identify the percentage of customers estimated to receive LCC savings or experience an LCC increase, in addition to the average LCC savings associated with a particular standard level. In addition to identifying ranges of impacts, DOE evaluates the LCC impacts of potential standards on identifiable subgroups of customers that may be disproportionately affected by a national standard.
Although significant conservation of energy is a separate statutory requirement for imposing an energy conservation standard, EPCA requires DOE, in determining the economic justification of a standard, to consider the total energy savings that are expected to result directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE uses the NIA spreadsheet results in its consideration of total projected energy savings.
In establishing classes of equipment, and in evaluating design options and the impact of potential standard levels, DOE sought to develop standards for distribution transformers that would not lessen the utility or performance of the equipment. (42 U.S.C. 6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today's final rule would lessen the utility or performance of the equipment under consideration in the rulemaking.
EPCA directs DOE to consider any lessening of competition that is likely to result from standards. It also directs the Attorney General of the United States (Attorney General) to determine the impact, if any, of any lessening of competition likely to result from a proposed standard and to transmit such determination to the Secretary, together with an analysis of the nature and extent of the impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)) DOE transmitted a copy of its proposed rule and NOPR TSD to the Attorney General with a request that the Department of Justice (DOJ) provide its determination on this issue. DOJ's response, that the proposed energy conservation standards are unlikely to have a significant adverse impact on competition, is reprinted at the end of this final rule.
Certain benefits of the amended standards for distribution transformers are likely to be reflected in improvements to the security and reliability of the Nation's energy system. Reductions in the demand for electricity may also result in reduced costs for maintaining the reliability of the Nation's electricity system. DOE conducted a utility impact analysis, described in section IV.K to estimate how standards may affect the Nation's needed power generation capacity. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))
Energy savings from the amended standards are also likely to result in environmental benefits in the form of reduced emissions of air pollutants and greenhouse gases associated with energy production. DOE reports the environmental effects from today's standards, and from each TSL it considered, in chapter 15 of the TSD for the final rule. DOE also reports estimates of the economic value of emissions reductions resulting from the considered TSLs (see section IV.M of this final rule).
EPCA allows the Secretary of Energy, in determining whether a standard is economically justified, to consider any other factors that the Secretary of Energy considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) Under this provision, DOE has also considered the matter of electrical steel availability. This factor is discussed further in sections IV.C.9. and IV.I.5.a.
As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a rebuttable presumption that an energy conservation standard is economically justified if the additional cost to the customer of a type of equipment that meets the standard is less than three times the value of the first-year of energy savings resulting from the standard, as calculated under the applicable DOE test procedure. DOE's LCC and PBP analyses generate values used to calculate the PBP for consumers of potential amended energy conservation standards. These analyses include, but are not limited to, the three-year PBP contemplated under the rebuttable presumption test. However, DOE routinely conducts an economic analysis that considers the full range of impacts to the customer, manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The results of that analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level (thereby supporting or rebutting the results of any three-year PBP analysis). The rebuttable presumption payback calculation is discussed in sections IV.F.3.j and V.B.1.c of this final rule.
DOE used two spreadsheet tools to estimate the impact of today's amended standards. The first spreadsheet
Additionally, DOE estimated the impacts of energy conservation standards for distribution transformers on utilities and the environment using a version of the Energy Information Administration's (EIA's) National Energy Modeling System (NEMS) for the utility and environmental analyses. The NEMS model simulates the energy sector of the U.S. economy. EIA uses NEMS to prepare its Annual Energy Outlook (
For the market and technology assessment, DOE develops information that provides an overall picture of the market for the equipment concerned, including the purpose of the equipment, the industry structure, and market characteristics. This activity includes both quantitative and qualitative assessments, based primarily on publicly available information. The subjects addressed in the market and technology assessment for this rulemaking included scope of coverage, definitions, equipment classes, types of equipment sold and offered for sale, and technology options that could improve the energy efficiency of the equipment under examination. Chapter 3 of the TSD contains additional discussion of the market and technology assessment.
This section addresses the scope of coverage for today's final rule, stating what equipment will be subject to amended standards.
Today's standards rulemaking concerns distribution transformers, which include three categories: Liquid-immersed, low-voltage dry-type (LVDT), and medium-voltage dry-type (MVDT). The definition of a distribution transformer was presented in EPACT 2005, then further refined by DOE when it was codified into 10 CFR 431.192 by the April 27, 2006, final rule for distribution transformer test procedures (71 FR 24972).
Additional detail on the definitions of each of these excluded transformers, which are defined at 10 CFR 431.192, can found in chapter 3 of the TSD.
Many stakeholders expressed support for the defined scope of coverage presented in the NOPR. (ABB, No. 158 at p. 5; Cooper, No. 165 at p. 2; HI, No. 151 at p. 12; KAEC, No. 149 at p. 4; NEMA, No. 170 at p. 8; PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7) NRECA pointed out that while some of its members might purchase distribution transformers outside the scope of coverage so few of these types of transformers are made it does not warrant a change in coverage. (NRECA, No. 172 at p. 4–5) Progress Energy agreed, noting that while utilities will occasionally purchase transformers outside of this range, it is a very small percentage of the total number of distribution transformers purchased. (PE, No. 192 at p. 4) EEI was not aware of any of member that purchased units outside of the current defined kVA range. (EEI, No. 185 at p. 5) Finally, BG&E and ComEd noted that DOE has spent a significant amount of time developing efficiency levels for each kVA size and that therefore they supported the current scope. (BG&E, No. 182 at p. 3; ComEd, No. 184 at p. 3) Power Partners was also in support of the current scope, but noted that if separate product classes were established for overhead transformers and network/vault transformers the kVA scope for those product classes should be aligned with the specific requirements for those product standards. (Power Partners, No. 155 at p. 3)
Several stakeholders expressed that additional kVA ranges should be added to the scope of coverage. Specifically, Schneider Electric requested that for LVDT products, the following kVA ranges would add value to the national impact benefits: 1kVA through 500kVA single phase and 3kVA through 1500kVA three phase. (Schneider, No. 180 at p. 4) Similarly, CDA requested an increased range, urging DOE to extend its kVA coverage to sizes about 2,500 kVA. (CDA, No. 153 at p. 2)
Earthjustice expressed concern over sealed and non-ventilating transformers. It felt that these products represented a potential loophole for smaller transformers in DL7 and noted that DOE should revise its definition to ensure these units do not displace covered units. (Earthjustice, No. 195 at p. 6) Similarly, Earthjustice noted revisions to the definition of “uninterruptible power supply transformer might be necessary” as some manufacturers are selling exempt UPS units, that are otherwise not covered, for general purpose applications at a cost of 30–40 percent lower than covered transformers. (Earthjustice, No. 195 at p. 6) CDA requested that DOE seek legislation to expand its scope to include power transformers. (CDA, No. 153 at p. 2)
Schneider Electric requested that DOE reevaluate several definitions in its scope of coverage. First, it asked that DOE address its tap ranges and the determination of covered equipment versus products versus exempt equipment to possibly capture further energy savings. Second, it requested that DOE re-evaluate special impedance transformers and ranges. Finally, it noted that because low voltage is limited to 600 volts and below, market conditions have created multiple voltages in the 1.2kV class of equipment, but current standards
DOE appreciates the comment on its scope of coverage. With respect to kVA, DOE's current standards are consistent with several NEMA publications. For liquid-immersed and medium-voltage dry-type transformers, both DOE coverage and that of NEMA's TP–1 standard extends to 833 kVA for single-phase units and 2500 kVA for three-phase units. For low-voltage dry-type units, both DOE coverage and that of NEMA's Premium specification extends to 333 kVA for single-phase units and
For sealed and nonventilating transformers, uninterruptible power supply transformers, special impedance transformers, and those with tap ranges of greater than twenty percent, DOE notes that these types of equipment are specifically excluded from standards under EPCA, as amended, 42 USC 6291 (35)(B)(ii)), as codified at 10 CFR 431.192.
Cooper Power systems requested clarification on several points relating to scope of coverage. Some transformers are built with the ability to output at multiple voltages, any number of which may fall within DOE's scope of coverage. For transformers having multiple nominal voltage ratings that straddle the present boundaries of DOE's scope of coverage (i.e., a secondary voltage of 600/1200 volts), Cooper recommended that DOE clarify whether the entire distribution transformer is exempt from efficiency standards. Cooper felt it was unclear if both configurations would have to meet the efficiency standard, neither would meet the standard, or only the secondary voltage of 600 would have to meet the standard. (Cooper Power Systems, No. 222 at p. 3) Second, for three-phase transformers with wye-connected phase windings or single-phase transformers that are rated for externally connecting in a wye configuration, where the phase-to-phase voltage exceeds the present boundaries of the definition of distribution transformer, Cooper requested that DOE clarify that these units are exempt from the standard because the secondary voltage exceeds 600 volts. (Cooper Power Systems, No. 222 at p. 3)
DOE clarifies that the definition of distribution transformer refers to a transformer having an output voltage of 600 volts or less, not having only an output voltage of less than 600 volts. If the transformer has an output of 600 volts or below and meets the other requirements of the definition, DOE considers it to be a distribution transformer within the scope of coverage and therefore subject to standards. This applies equally to transformers with split secondary windings (as in Cooper's first example) and to three-phase transformers where the delta connection may fall below 601 volts and the wye connection may not. DOE also clarifies that once it is determined that a transformer is subject to standards, DOE's test procedure requires that a transformer comply with the standard when tested in the configuration that produces the greatest losses, regardless of whether that configuration alone would have placed the transformer at-large within the scope of coverage under 10 CFR 431.192.
In the October 12, 2007, final rule on energy conservation standards for distributions transformers, DOE codified into 10 CFR 431.192 the definition of an underground mining distribution transformer as follows:
In that same final rule, DOE also clarified that although it believed those transformers were within its scope of coverage, it was not establishing energy conservation standards for underground mining transformers. At the time, DOE recognized that the mining transformers were subject to unique and extreme dimensional constraints that impact their efficiency and performance capabilities. Therefore, DOE established a separate equipment class for mining transformers and stated that it might consider energy conservation standards for such transformers at a later date. Although DOE did not establish energy conservation standards for such transformers, it also did not add underground mining transformers to the list of excluded transformers in the definition of a distribution transformer. DOE maintained that it had the authority to cover such equipment if, during a later analysis, it found technologically feasible and economically justified energy conservation standard levels. 72 FR 58197.
Several stakeholders commented on DOE's definition for mining transformers during the current rulemaking. Joy Global Surface Mining recommended that surface mining transformers be added to the exemption list under the following definition: “Surface mining transformer is a medium-voltage dry-type distribution transformer that is built only for installation in a surface mine, on-board equipment for use in a surface mine or for equipment used for digging or drilling above ground. It shall have a nameplate which identifies the transformer as being for this use only.” (Joy Global Surface Mining, No. 214 at p. 1) ABB and PEMCO agreed that ordinary (i.e., non-surface) mining transformers should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 158 at p. 5; PEMCO, No. 183 at p. 2) PEMCO felt strongly that underground mining transformers should be in the list of transformers excluded from the efficiency standard, pointing out that “underground mining transformers require the use of much heavier cores and thus have an even larger reason to be excluded than some product types already excluded.” (PEMCO, No. 183 at p. 2) NEMA commented that all underground mining transformers should be made exempt from the DOE energy efficiency regulation for MVDT due to the special circumstances they must operate under; dimensions and weight are critical for these products, and to reduce the weight and size these transformers are operated near full load, therefore, compliance with DOE regulation will not optimize efficiency. (NEMA, No. 170 at p. 11) Cooper Power suggested that DOE expand the definition of mining transformers to include both liquid filled and dry-type transformers, and specify that this only applies to transformers used inside the mine itself; Cooper supports the exclusion of these transformers from efficiency standards. (Cooper, No. 165 at p. 2) ABB asserted that the definition of mining transformers should be expanded to include transformers used for digging or tunneling. Furthermore, ABB asserted that such equipment should be moved to the exclusion list in 10 CFR 431.192 (5). (ABB, No. 158 at p. 6)
DOE has learned from comments received throughout the rulemaking that mining transformers are subject to several constraints that are not usually concerns for transformers used in general power distribution. Because space is critical in mines, an underground mining transformer may be at a considerable disadvantage in meeting an efficiency standard. Underground mining transformers are further disadvantaged by the fact that they must supply power at several output voltages simultaneously. For today's rule, DOE will again set no standards for underground mining transformers but expands this treatment to include surface mining transformers. Moreover, as commenters point out, surface mining transformers are used to operate specialized machinery which carries space constraints of its own. Furthermore, mining transformers in
In view of the above, DOE recognizes a potential means to circumvent energy efficiency standards requirements for distribution transformers. Therefore, DOE continues to leave both underground and surface mining transformers off of the list of distribution transformers that are not covered under 10 CFR 431.192, but instead reserve a separate equipment class for mining transformers. DOE may set standards in the future if it believes that underground or surface mining transformers are being purchased as a way to circumvent energy conservation standards for distribution transformers otherwise covered under 10 CFR 431.192.
In the 2012 NOPR, DOE proposed to continue to not set standards for step-up transformers, as these transformers are not ordinarily considered to be performing a power distribution function. However, DOE was aware that step-up transformers may be able to be used in place of step-down transformers (i.e., by operating them backwards) and may represent a potential means to circumvent any energy efficiency requirements as standards increase. In the NOPR, DOE requested comment regarding this issue.
Many stakeholders expressed support for adding step-up transformers to the scope of coverage. Howard Industries commented that there is no practical reason for excluding these transformers, and that DOE should require step-up transformers to meet the same efficiency as step-down, as long as either the output or input voltage is 600 volts or less. They expressed concern that eliminating these transformers would present a potential loophole. (HI, No. 151 at p. 12) Prolec-GE agreed, noting that to eliminate this loophole, step-up transformers should at least indicate their purpose on their nameplates. (Prolec-GE, No. 146 at pp. 55–56) However, Earthjustice commented that simply requiring nameplates for these transformers would be unlikely to deter some users from installing step-up transformers in place of covered transformers. They expressed their concern that DOE had not addressed potential loopholes that had been identified in the rulemaking. (Earthjustice, No, 195 at pp. 5–6) Advocates agreed with comments made during negotiations arguing that step-up transformers should be covered by new standards due to similarities to distribution transformer that could easily lead to substitution and circumvention. (Advocates, No. 186 pp. 5–6) Finally, Berman Economics commented that because step-up transformers had not been included in the 2007 final rule, leaving them uncovered may lead to unintended circumvention. (Berman Economics, No. 221 at p. 7)
Other stakeholders expressed their support for DOE's decision to not separately define and set standards for step-up transformers. (Cooper, No. 165 at p. 2; NEMA, No. 170 at p. 8; BG&E, No. 182 at p. 3) APPA and EEI agreed, pointing out that while in emergency conditions one can occasionally see a step-up transformer used as a step-down transformer, these situations are rare and overall do not result in significant transformer efficiency loss. (APPA, No. 191 at p. 6; EEI, No. 185 at p. 5–6) Progress Energy commented similarly, noting that they do not purchase step-up transformers for use as step-down transformers. (PE, No. 192 at p. 4) ABB and Prolec-GE agreed with the decision to not set separate standards for step-up transformers but requested that these transformers be identified on their nameplate uniformly across the industry. (ABB, No. 158 at p. 6; Prolec-GE, No. 177 at p. 7) PEMCO commented that no action was necessary as the product class falls outside the current definition of a distribution transformer. (PEMCO, No. 183 at p. 2) Schneider Electric sought clarification given the existing definition in section 431.192 and noted that the current standards do not exclude step-up LVDT transformers as written. (Schneider, No. 180 at p. 4)
For today's rule, DOE continues to consider step-up transformers as equipment that is not covered, because they do not perform a function traditionally viewed as power distribution. Transformer coverage is not determined simply based on whether the transformer is stepping voltage up or down. DOE clarifies that liquid-immersed step-up transformers usually fall outside of the rulemaking scope of coverage because of limits on input and output voltage, and not because they are excluded per se. Liquid-immersed and medium-voltage dry-type transformers tend to fall within DOE's scope of coverage only if stepping down voltage because the input voltage upper limit (34.5 kV) is much greater than the output voltage limit (600 V). No such distinction exists for LVDT transformers, which are covered for input and output voltages of 600 V or below, regardless of whether stepping voltage up or down. Nonetheless, because of the circumvention risk, DOE will monitor the use of step-up transformers and consider establishing standards for them, if warranted.
10 CFR 431.192 defines the term “low-voltage dry-type distribution transformer” to be a distribution transformer that has an input voltage of 600 V or less; is air-cooled; and does not use oil as a coolant.
Because EPACT 2005 prescribed standards for LVDTs, which DOE incorporated into its regulations at 70 FR 60407 (October 18, 2005) (codified at 10 CFR 431.196(a)), LVDTs were not included in the 2007 standards rulemaking. As a result, the settlement agreement following the publication of the 2007 final rule does not affect LVDT standards. Without regard to whether DOE may have a statutory obligation to review standards for LVDTs, DOE has analyzed all three transformer types and is proposing standards for each in this rulemaking.
Negotiation participants noted that both network/vault transformers and “data center” transformers may experience disproportionate difficulty in achieving higher efficiencies because of certain features that may affect consumer utility. (ABB, Pub. Mtg. Tr., No. 89 at p. 245) In the NOPR, DOE reprinted definitions for these terms, which were proposed at various points by committee members. 77 FR 7301. DOE sought comment in its NOPR about whether it would be appropriate to establish separate equipment classes for any of the following types and, if so, how such classes might be defined such that it was not financially advantageous for customers to purchase transformers in either class for general use. Please see IV.A.2.c for further discussion of DOE's equipment classes in today's final rule.
DOE divides covered equipment into classes by: (a) The type of energy used; (b) the capacity; and/or (c) any performance-related features that affect
(a) Type of transformer insulation—liquid-immersed or dry-type,
(b) Number of phases—single or three,
(c) Voltage class—low or medium (for dry-type units only), and
(d) Basic impulse insulation level (for medium-voltage dry-type units only).
On August 8, 2005, the President signed into law EPACT 2005, which contained a provision establishing energy conservation standards for two of DOE's equipment classes—EC3 (low-voltage, single-phase dry-type) and EC4 (low-voltage, three-phase dry-type). With standards thereby established for low-voltage dry-type distribution transformers, DOE no longer considered these two equipment classes for standards during the 2007 final rule. In today's rulemaking, however, DOE has decided to address all three types of distribution transformers and is establishing new standards for all three types of distribution transformers, including low-voltage dry-type distribution transformers. Table IV.1 presents the ten equipment classes proposed in the NOPR and finalized in this rulemaking and provides the associated kVA range with each.
During the previous rulemaking, DOE solicited comments about how it should treat distribution transformers filled with an insulating fluid of higher flash point than that of traditional mineral oil. 71 FR 44369 (August 4, 2006). Known as “less-flammable, liquid-immersed” (LFLI) transformers, these units are marketed to some applications where a fire would be especially costly and traditionally served by the dry-type market, such as indoor applications.
During preliminary interviews with manufacturers, DOE was informed that LFLI transformers might offer the same utility as dry-type transformers since they were unlikely to catch fire. Manufacturers also stated that LFLI transformers could have a minor efficiency disadvantage relative to traditional liquid-immersed transformers because their more viscous insulating fluid requires more internal ducting to properly circulate.
In the October 2007 standards final rule, DOE determined that LFLI transformers should be considered in the same equipment class as traditional liquid-immersed transformers. DOE concluded that the design of a transformer (i.e., dry-type or liquid-immersed) was a performance-related feature that affects the energy efficiency of the equipment and, therefore, dry-type and liquid-immersed should be analyzed separately. Furthermore, DOE found that LFLI transformers could meet the same efficiency levels as traditional liquid-immersed units. As a result, DOE did not separately analyze LFLI transformers, but relied on the analysis for the mineral oil liquid-immersed transformers. 72 FR 58202 (October 12, 2007).
DOE revisited the issue in this rulemaking in light of additional research on LFLI transformers and conversations with manufacturers and industry experts. DOE first considered whether LFLI transformers offered the same utility as dry-type equipment, and came to the same conclusion as in the last rulemaking. While LFLI transformers can be used in some applications that historically use dry-type units, there are applications that cannot tolerate a leak or fire. In these applications, customers assign higher utility to a dry-type transformer. Since LFLI transformers can achieve higher efficiencies than comparable dry-type units, combining LFLIs and dry-types into one equipment class may result in standard levels that dry-type units are unable to meet. Therefore, DOE decided not to analyze LFLI transformers in the same equipment classes as dry-type distribution transformers.
Similarly, DOE revisited the issue of whether or not LFLI transformers should be analyzed separately from traditional liquid-immersed units. DOE concluded, once again, that LFLI transformers could achieve any efficiency level that mineral oil units could achieve. Although their insulating fluids are slightly more viscous, this disadvantage has little efficiency impact and diminishes as efficiency increases and heat dissipation requirements decline. Furthermore, at least one manufacturer suggested that LFLI transformers might be capable of higher efficiencies than mineral oil units because their higher temperature tolerance may allow the unit to be downsized and run hotter than mineral oil units. For these reasons, DOE believes that LFLI transformers would not be disproportionately affected by standards set in the liquid-immersed equipment classes. Therefore, DOE did not consider LFLI in a separate equipment class.
During negotiations and in response to the NOPR, several parties raised the question of whether pole-mounted, pad-mounted, and possibly other types of
APPA, ASAP, BG&E, ComEd, Howard, Progress Energy, Pepco, and Power Partners all supported separation of pole-mounted transformers into separate equipment classes for the above-mentioned reasons. Size and weight was the most commonly-cited reason. (APPA, No. 191 at p. 7, No. 237 at p. 3; ASAP, No. 146 at pp. 69–70; BG&E, No. 146 at p. 69, No. 182 at p. 4; ComEd, No. 184 at p. 8, No. 227 at p. 2; HI, No. 151 at p. 4, No. 226 at p. 1; PE, No. 192 at p. 5, Pepco, No. 146 at p. 68, No. 145 at pp. 2–3; Power Partners, No. 155 at p. 2)
ABB, NEMA, Berman Economics, Cooper, EEI, AK Steel, and KAEC stated that the increase in standards did not warrant separate treatment of pole-mounted transformers, stating that separation adds complexity to the regulation and does not allow manufacturers of both pole-mounted and other types of liquid-immersed distribution transformers to standardize manufacturing and design practices across product lines. (ABB, No. 158 at p. 6; Berman Economics, No. 150 at p. 19, No. 221 at p. 4; Cooper, No. 165 at p. 3; EEI, No. 229 at p. 2; AK Steel, No. 230 at p. 3; KAEC, No. 149 at p. 4; NEMA, No. 170 at p. 12)
The Advocates, NEMA, and Prolec-GE commented that separation may be warranted but only if DOE opted for higher standards than were proposed in the NOPR. (Advocates, No. 158 at p. 13; Prolec-GE, No. 177 at p. 3; NEMA, No. 170 at p. 14)
NEMA further noted that the matter was complicated and that there were advantages to both approaches. (NEMA, No. 225 at p. 4) Finally, EEI and NRECA commented that DOE should explore the matter but in the next rulemaking for distribution transformers. (EEI, No. 185 at p. 7; NRECA, No. 172 at p. 7) NRECA supported the concept of separation, but this support was qualified by concerns that DOE might raise the efficiency levels. (NRECA, No. 172 at pp. 5–6)
Based on the array of views on this issue and the potential energy and cost savings to weigh, DOE conducted further analysis of this of liquid-immersed transformers issue and presented the findings of its supplementary analysis at a public meeting on June 20, 2012. 77 FR 32916 (June 4, 2012). In today's rule, DOE has chosen not to separate pad and pole-mounted transformers. DOE's concerns about steel competitiveness and availability were not resolved through comments in response to both the NOPR and the supplemental analysis. Moreover, the comments did not demonstrate that establishing standards for transformers separated by those on pads and those on poles was superior to the approach taken in the proposed rule. Therefore, DOE chose not to finalize separate standards for pad-mounted transformers in today's final rule. However, DOE appreciates the concerns about allowing manufacturers to standardize manufacturing and design practices across product lines. DOE may consider establishing separate equipment classes for pole-mounted distribution transformers in the future, but at present believes the equipment class structure proposed in the NOPR to be justified for today's final rule.
During negotiations, several parties raised the question of whether network, vault, and possibly other types of liquid-immersed transformers should be considered in separate equipment classes. In the 2012 NOPR, DOE considered separating these types of transformers and sought comment from manufacturers on this matter.
In response to the NOPR, many stakeholders commented on separation of network and vault transformers into new equipment classes. Several stakeholders expressed support for separate equipment classes for network and vault transformers, noting that they agreed with the definition put forth by the negotiations working group. (ABB, No. 158 at p. 6; Adams Electrical Coop, No. 163 at p. 2; APPA, No. 191 at p. 6; BG&E, No. 182 at p. 3; BG&E, No. 223 at p. 2; CFCU, No. 190 at p. 1; ConEd, No. 184 at p. 4; EEI, No. 229 at p. 2; KAEC, No. 149 at p. 4; NEMA, No. 146 at p. 67; NEMA, No. 170 at p. 11; NRECA, No. 172 at p. 5; NRECA, No. 228 at pp. 2–3; Power Partners, No. 155 at p. 2) Stakeholders felt that this separate equipment class should have efficiency standards that are unchanged from the levels that have been in effect since January 1, 2010, set in the 2007 final rule. (Cooper, No. 165 at p. 3; Cooper Power Systems, No. 222 at p. 4; EEI, No. 185 at p. 3; NEMA, No. 170 at p. 8; PE, No. 192 at p. 5; Prolec-GE, No. 177 at pp. 7, 12; PE, No. 192 at p. 8)
Many manufacturers noted that network/vault transformers should be separated based on the tight size and space restrictions placed on them. (NEMA, No. 225 at p. 3; Prolec-GE, No. 146 at p. 15; ABB, No. 158 at p. 9) In many cases, manufacturers stated that higher efficiency transformers cannot fit into existing vaults and still maintain required safety and maintenance clearance. (NEMA, No. 170 at p. 3) Stakeholders argued that any increase in size due to increased efficiency standards would eliminate any economic benefit from higher efficiency due to the extremely high costs of modifying existing vault or other underground infrastructure in urban areas. (Adams Electric Coop, No. 163 at p. 2; BG&E, No. 223 at pp. 2–3; ConEd, No. 184 at p. 4; NRECA, No. 172 at p. 3; Pepco, No. 145 at p. 23; ABB, No. 158 at p. 9; Howard Industries, No. 226 at pp. 1–2; APPA, No. 191 at p. 4; Pepco, No. 145 at p. 3; ConEd, No. 236 at pp. 1–2) Others pointed out that expansion of vaults and manholes in city environments is sometimes even physically impossible due to space constraints. (ConEd, No. 184 at p. 4) Howard Industries noted that often American National Standards Institute (ANSI) standards govern the sizes of these types of transformers based on established maximum dimensional constraints due to vault sizing. (HI, No. 151 at p. 3) Prolec-GE commented that the application of these transformers not only requires them to be compact, but also built to a much higher level of ruggedness and durability. (Prolec-GE, No. 238 at pp. 1–2)
Con Edison, who is the largest user of network- and vault-based distribution transformers in the United States, pointed out that while it agrees with separation of network-based transformers, modifications were needed to the definition presented in Appendix 1–A to include transformers purchased by Con Edison, who is the largest user of network- and vault-based distribution transformers in the United States. (ConEd, No. 236 at p. 2)
Other stakeholders noted that while network and vault transformers could experience dimensional problems at higher efficiencies, these problems are
Multiple stakeholders expressed hesitation about separating vault transformers. Berman Economics recommended that DOE consider a separate class for network transformers only, as the additional electronics and protections required of a networked transformer likely would make it an uneconomic substitute for a non-networked transformer, an argument that could not be made for vault transformers. (Berman Economics, No. 221 at p. 5) Furthermore, Advocates pointed out that vault transformers may be a compliance loophole/risk and, at minimum, nameplate marking that reads “For installation in a vault only,” should be required for this equipment. (Advocates, No. 235 at p. 4) Others noted that the idea of vault transformers being used as substitutes for pad-mounted transformers is “fraught with over-simplifications and faulty assumptions.” (APPA, No. 237 at pp. 2–3) They believed that substitution would not occur if DOE defined and carved out network and vault transformers per the IEEE definitions. (APPA, No. 237 at pp. 2–3) It was also pointed out that utilities pay as much as two times as much for a vault transformer as for pad-mounted units of similar capacity. (EEI, No. 229 at p. 5)
DOE appreciates the attention and depth of thought given by stakeholders to this nuanced rulemaking issue. At this time, DOE believes that establishing a new equipment class for network and vault based transformers is unnecessary. It is DOE's understanding that there is no technical barrier that prevents network and vault based transformers from achieving the same levels of efficiency as other liquid-immersed distribution transformers. However, DOE does understand that there are additional costs, besides those to the physical transformer, which may be incurred when a replacement transformer is significantly larger than the original transformer and does not allow for the necessary space and maintenance clearances. Rather than establishing a new equipment class, DOE has considered the costs for such vault replacements in the NIA. Please see section X. Therefore, as stated, DOE is not establishing a new equipment class for these transformer types, but may consider doing so in a future rulemaking.
During negotiations, several parties raised the question of whether liquid-immersed distribution transformers should have standards set according to BIL rating, as do medium-voltage dry-type distribution transformers. (ABB, Pub. Mtg. Tr., No. 89 at p. 218) Other parties responded in response to the NOPR with suggestions about how to address BIL ratings in liquid-immersed distribution transformers. NEMA pointed out that as BIL increases, a greater volume of core material is needed, adding both expense and no-load losses. (NEMA, No. 170 at p. 4) Cooper agreed with separation by BIL, pointing out that “standards by BIL level will help differentiate transformers that require more insulation and that are less efficient by nature.” (Cooper, No. 165 at p. 3) Howard Industries opined that it felt 200 kV BIL and higher transformers should have their own category whose efficiency levels were capped at those set in the 2007 Final Rule. It noted that high BIL ratings require additional insulation to meet American National Standards Institute (ANSI) requirements and such additional insulation limits the achievable efficiency for these transformers. (HI, No. 151 at p. 12) Berman Economics supported separation, and commented that DOE could split at 200 kV if these transformers would not be cheaper than 150 BIL transformers at the newly set standard. (Berman Economics, No. 221 at p. 6) BG&E does not purchase 200 kV BIL transformers but supported maintaining the current 2007 Final Rule efficiency levels for these transformers due to construction and weight limitations. (BG&E, No. 223 at p. 2)
Several stakeholders felt that separate standards should be set for all transformers with a BIL of 150 kV or higher. (NRECA, No. 228 at p. 3; Advocates No. 235 at pp. 4–5; EEI, No. 229 at pp. 5–6; APPA, No. 237 at p. 3) Stakeholders who supported a split at 150 kV felt that all transformers with BILs above this level should not have increasing standards in this rule; the standards should remain at efficiency levels set in the 2007 final rule. (NEMA, No. 225 at p. 3–4; Howard Industries, No. 226 at p. 2) Prolec-GE pointed out that a class of only 200 kV and above is of extremely limited volume and provides no benefit, stating that there is a significant step up in cost for higher efficiencies at 150 kV BIL. (Prolec-GE, No. 238 at p. 2) “To prevent substitution of higher BIL rated transformers as a means of circumventing the efficiency standard, Cooper recommends using coil voltage as a defining criterion for the 150 kV BIL class. Transformers having an insulation system designed to withstand 150 kV BIL and either a line-to-ground or line-to-neutral voltage that is 19 kV (e.g. 34500GY/19920 or 19920 Delta) or greater would be required to qualify as a true 150 kV BIL distribution transformer.” (Cooper Power Systems, No. 222 at pp. 3–4)
NEMA and KAEC recommended that the efficiency levels proposed in the NOPR be set for liquid-immersed transformers at 95 kV BIL and below only, while all other BILs remain at the current standard. (NEMA, No. 170 at p. 10; KAEC, No. 149 at p. 5) Prolec-GE agreed that the liquid-immersed transformers should be separated at 95 kV BIL and below and above 95 kV. It also suggested that DOE add more design lines for these equipment classes, as it did not believe the scaling was accurate. (Prolec-GE, No. 177 at p. 8) Power Partners commented that there should be several BIL divisions for liquid-immersed distribution transformers and suggested that DOE have equipment classes for the following: 7200/12470Y 95BIL, 14400/2490Y 125BIL, 19920/34500Y 150BIL, and 34500 200 BIL. (Power Partners, No. 155 at p. 3)
Several stakeholders supported the concept of exploring how BIL affects efficiency but felt that it was not a significant enough issue to delay publication of this rule. They proposed that DOE investigate this concept in the next rulemaking. (PE, No. 192 at p. 6; NRECA, No. 172 at p. 6; EEI, No. 185 at p. 8; ComEd, No. 184 at p. 10; BG&E, No. 182 at p. 5; APPA, No. 191 at p. 7) Similarly, ABB commented that at the current proposed levels, ABB does not recommend moving to a separate BIL range for liquid-immersed transformers. If efficiency levels were to increase, ABB would support a change, but did not feel it is warranted with the proposed levels. (ABB, No. 158 at p. 7) HVOLT agreed that at proposed levels, separating by BIL was likely not needed, and pointed out that efficiency impacts of varied BIL were smaller in liquid-immersed transformers than in dry-type transformers. (HVOLT, No. 146 at p. 73)
DOE appreciates all of the input regarding separating standards for different BIL ratings of liquid-immersed distribution transformers. Similar to network- and vault-based transformers, DOE may give strong consideration to establishing equipment classes by BIL rating when considering increased
During negotiations, participants noted that data center transformers may experience disproportionate difficulty in achieving higher efficiencies due to certain features that may affect consumer utility. In the NOPR, DOE proposed the definition below for data center transformers and sought comment both on the definition itself, and whether to separate data center transformers into their own equipment class. It noted that separation, the equipment classes must be defined such that it would not be financially advantageous for consumers to purchase data center transformers for general use.
i. Data center transformer means a three-phase low-voltage dry-type distribution transformer that—
(i) is designed for use in a data center distribution system and has a nameplate identifying the transformer as being for this use only;
(ii) has a maximum peak energizing current (or in-rush current) less than or equal to four times its rated full load current multiplied by the square root of 2, as measured under the following conditions—
1. during energizing of the transformer without external devices attached to the transformer that can reduce inrush current;
2. the transformer shall be energized at zero +/− 3 degrees voltage crossing of a phase. Five consecutive energizing tests shall be performed with peak inrush current magnitudes of all phases recorded in every test. The maximum peak inrush current recorded in any test shall be used;
3. the previously energized and then de-energized transformer shall be energized from a source having available short circuit current not less than 20 times the rated full load current of the winding connected to the source; and
4. the source voltage shall not be less than 5 percent of the rated voltage of the winding energized; and
(vii) is manufactured with at least two of the following other attributes:
1. Listed as a Nationally Recognized Testing Laboratory (NRTL), under the Occupational Safety and Health Administration, U.S. Department of Labor, for a K-factor rating greater than K–4, as defined in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition, Dry-Type General Purpose and Power Transformers;
2. temperature rise less than 130°C with class 220
3. a secondary winding arrangement that is not delta or wye (star);
4. copper primary and secondary windings;
5. an electrostatic shield; or
6. multiple outputs at the same voltage a minimum of 15° apart, which when summed together equal the transformer's input kVA capacity.
Several stakeholders responded to the request for comment on data center transformers. HVOLT agreed with the idea of creating a separate equipment class for data center transformers, but noted that “the concept of the inrush current held to four times rating is not accurate.” (HVOLT, No. 146 at p. 65) NEMA and KAEC supported the establishment of a separate equipment class for data center transformers as well as the definition developed by the working group and recommended that the efficiency levels for this new class remain at EL0, which is equivalent to the levels of NEMA's standard TP–1 2002. (NEMA, No. 170, at p. 9; KAEC, No. 149 at p. 4 NEMA, No. 170 at p. 5) ABB agreed, noting that it supported the definition developed by the working group and a separate equipment class for LVDT data center transformers. (ABB, No. 158 at p. 6) Cooper Power supported the definition, and recommended that the efficiency level for these transformers remain at the baseline. (Cooper, no. 165 at p. 3) NRECA noted that few of its members serve data centers and that it does not have any data on load factors and peak responsibility factors for data centers, but pointed to Uptime Institute and Lawrence Berkeley National Laboratories as sources that may have such data available. (NRECA, No. 172 at p. 5) Howard Industries commented that this proposal would not directly affect it or its products and until further information is given it could give no response on whether or, so had not there is a necessity for establishing a separate equipment class at this time. (HI, No. 151 at p. 3) Finally, Cooper power suggested that, if a separate definition for data center transformers is adopted, a 75 percent load level should be used in the test procedure. (Cooper, No. 165 at p. 3)
DOE appreciates the comments received about data center transformers. In today's rule, DOE is not establishing separate equipment classes for data center transformers for several reasons. First, after reviewing the proposed definition with technical experts, DOE has come to believe that not all of the listed clauses in the definition are directly related to efficiency as it would pertain to the specific operating environment of a data center. For example, the requirement for copper windings would seem generally to aid efficiency rather than hinder it. Second, DOE believes that there may be risk of circumvention of standards and that a transformer may be built to satisfy the data center definition without significant added expense. Third, DOE understands that operators of data centers are generally themselves interested in equipment with high efficiencies because they often face large electricity costs. If that were true, they may be purchasing at or above today's standard and be unaffected by the rule. Finally, DOE understands that the most significant technical requirement of data center transformers to be related to inrush current. In the worst possible case, DOE understands that operators of data center transformers can (and perhaps already do) take measures to limit inrush current external to the transformer. For these reasons, DOE is not establishing a separate equipment class for data center transformers in today's rule.
Progress Energy recommended to DOE that “any change in efficiency requirements fully investigates the impact of higher sound levels and/or vibration.” (PE No, 92 at p. 10) Progress Energy noted that higher sound or vibration levels or both will be of significant concern where users are nearby. (PE, No. 192 at p. 10) Southern California Edison reported that it had experienced ferroresonance issues with amorphous core transformers in the past. Further, it expressed ferroresonance concerns about lower loss designs with M2 core steel. (Southern California Edison, No. 239 at p. 1) However, neither EEI nor APPA were aware of vibration or acoustic noise issues associated with higher efficiency transformers but conceded that, if there were to be ferroresonance issues with higher efficiency transformers, it could impact customer satisfaction, especially in residential areas. (EEI, No. 185 at p. 19; APPA, No. 191 at p. 13–14) Cooper Power Systems
DOE understands that, in certain applications, noise, and vibration, or harshness (NVH) could be especially problematic. However, based on comments, DOE does not believe that NVH concerns would be significant under the efficiency levels proposed and it does not propose to establish equipment classes using NVH as criteria for today's rule. DOE notes that several manufacturers offer technologies that reduce NVH in cases where it may be of unusual concern.
As discussed in section IIII.A, many distribution transformers have primary and secondary windings that may be reconfigured to accommodate multiple voltages. In some configurations, the transformer may operate less efficiently.
NEMA commented that DOE should exclude from further consideration transformers with multiple primary windings, because they are disadvantaged in meeting higher efficiencies. (NEMA, No. 225 at p. 6) On the other hand, Prolec-GE commented that dual voltage distribution transformers should be included and treated the same as high BIL units, and expressed concern about 7200 X 14400 volt transformers where it could be less expensive for a user to purchase the dual voltage unit than to purchase a 14400 volt single voltage unit. Further, Prolec-GE believes that this issue is limited to simpler dual voltage ratings where the ratio of the two primary voltages is exactly 2:1, and that this potential loophole was not intended under the proposed regulations. (Prolec-GE, No. 238 at p. 2)
For the reason outlined in view of this Prolec-GE comment, DOE is not establishing equipment classes by multivoltage capability in today's final rule. Nevertheless, DOE may consider doing so in future rulemakings, or consider modification of the test procedure as discussed in III.A.4, Dual/Multiple-Voltage Primary Windings.
A primary consideration in establishment of equipment classes is whether or not the equipment under consideration offers differential utility to the consumer. DOE sought comment on the establishment of a number of equipment classes, including pole-mounted, data-center, network/vault-based, and high BIL distribution transformers to explore whether stakeholders believed equipment utility could be affected. ABB commented that the levels proposed in the NOPR were unlikely to reduce equipment performance or utility. (ABB, No. 158 at p. 10)
Although most stakeholder discussion of space-constrained applications centered around network/vault-based distribution transformers, Howard Industries mentioned another compact application—“ranchrunners”—and requested a separate equipment class for such units (HI, No. 151 at p. 5) Based on the limited data submitted, DOE does not understand ranchrunners to be used in applications where even minimal size increases would necessarily trigger great cost increases. Furthermore, DOE does not believe large size or weight increases are likely at the standard levels under consideration. DOE may consider further consideration of the impact of increased size and weight in future rulemakings, but is not establishing separate equipment classes for ranchrunners in today's final rule.
The technology assessment provides information about existing technology options to construct more energy-efficient distribution transformers. There are two main types of losses in transformers: No-load (core) losses and load (winding) losses. Measures taken to reduce one type of loss typically increase the other type of losses. Some examples of technology options to improve efficiency include: (1) Higher-grade electrical core steels, (2) different conductor types and materials, and (3) adjustments to core and coil configurations.
In consultation with interested parties, DOE identified several technology options and designs for consideration. These technology options are presented in Table IV.2 Further detail on these technology options can be found in chapter 3 of the final rule TSD.
HYDRO-Quebec (IREQ) notified DOE that a new iron-based amorphous alloy ribbon for distribution transformers was developed that has enhanced magnetic properties while remaining ductile after annealing. Further, IREQ noted that a distribution transformer assembly using this technology has been developed. (IREQ, No. 10 at pp. 1–2)
In response to the NOPR, HYDRO-Quebec offered more information on their iron-based amorphous alloy ribbon. It noted that it has two technologies to produce this amorphous
DOE understands that Hydro-Quebec and others worldwide are conducting research on cost-effective manufacture of amorphous core transformers, and believes that such efforts may ultimately save energy and economically benefit consumers. At the present, however, DOE does not understand such technology to necessarily enable achievement of higher efficiency levels. Furthermore, DOE did not attempt to model such technology in its engineering analysis because it could not obtain data on what such technology costs when applied at commercial scales.
As noted previously, core deactivation technology employs the concept that a system of smaller transformers can replace a single, larger transformer. For example, three 25 kVA transformers operating in parallel could replace a single 75 kVA transformer.
DOE understands that winding losses are proportionally smaller at lower load factors, but for any given current, a smaller transformer will experience greater winding losses than a larger transformer. As a result, those losses may be more than offset by the smaller transformer's reduced core losses. As loading increases, winding losses become proportionally larger and eventually outweigh the power saved by using the smaller core. At that point, the control unit (which consumes little power itself) switches on an additional transformer, which reduces winding losses at the cost of additional core losses. The control unit knows how efficient each combination of transformers is for any given loading, and is constantly monitoring the unit's power output so that it will use the optimal number of cores. In theory, there is no limit to the number of transformers that may operate in parallel in this sort of system, but cost considerations would imply there is an optimal number.
In response to the NOPR, Progress Energy noted that the response time of core deactivation systems might impair power quality by increasing the transformer impedance during the initial cycles of motor starting events. (PE, No. 171 at p. 1) DOE spoke with a company that is developing a core deactivation technology. Noting that many dry-type transformers are operated at very low loadings a large percentage of the time (e.g., a building at night), the company seeks to reduce core losses by replacing a single, traditional transformer with two or more smaller units that could be activated and deactivated in response to load demands. In response to load demand changes, a special unit controls the transformers and activates and/or deactivates them in real-time.
Although core deactivation technology has some potential to save energy over a real-world loading cycle, those savings might not be represented in the current DOE test procedure. Presently, the test procedure specifies a single loading point of 50 percent for liquid-immersed and MVDT transformers, and 35 percent for LVDT. The real gain in efficiency for core deactivation technology comes at loading points below the root mean square (RMS) loading specified in the test procedure, where some transformers in the system could be deactivated. At loadings where all transformers are activated, which may be the case at the test procedure loading, the combined core and coil losses of the system of transformers could exceed those of a single, larger transformer. This would result in a lower efficiency for the system of transformers compared to the single, larger transformer.
In response to the NOPR, Progress Energy Carolinas, Inc. commented that core deactivation is not a proven technology and would subject utility customers to lower reliability.
DOE acknowledges that operating a core deactivation bank of transformers instead of a single unit may save energy and lower LCC for certain consumers. At present, however, DOE is adopting the position that each of the constituent transformers must comply with the energy conservation standards under the scope of the rulemaking.
DOE understands that several companies worldwide are commercially producing three-phase transformers with symmetric cores—those in which each leg of the transformer is identically connected to the other two. The symmetric core uses a continuously wound core with 120-degree radial symmetry, resulting in a triangularly shaped core when viewed from above. In a traditional core, the center leg is magnetically distinguishable from the other two because it has a shorter average flux path to each leg. In a symmetric core, however, no leg is magnetically distinguishable from the other two.
One manufacturer of symmetric core transformers cited several advantages to its design. These include reduced weight, volume, no-load losses, noise, vibration, stray magnetic fields, inrush current, and power in the third harmonic. Thus far, DOE has seen limited cost and efficiency data for only a few symmetric core units from testing done by manufacturers. DOE has not seen any designs for symmetric core units modeled in a software program.
DOE understands that, because of zero-sequence fluxes associated with wye-wye connected transformers, symmetric core designs are best suited to delta-delta or delta-wye connections. While traditional cores can circumvent the problem of zero-sequence fluxes by introducing a fourth or fifth unwound leg, core symmetry makes extra legs inherently impractical. Another way to mitigate zero-sequence fluxes comes in the form of a tertiary winding, which is delta-connected and has no external connections. This winding is dormant when the transformer's load is balanced across its phases. Although symmetric core designs may, in theory, be made tolerant of zero-sequence fluxes by employing this method, this would come at extra cost and complexity.
Using this tertiary winding, DOE believes that symmetric core designs can service nearly all distribution transformer applications in the United States. Most dry-type transformers have a delta connection and would not require a tertiary winding. Similarly, most liquid-immersed transformers serving the industrial sector have a delta connection. These market segments could use the symmetric core design without any modification for a tertiary winding. However, in the United States most utility-operated distribution transformers are wye-wye connected. These transformers would require the
DOE understands that symmetric core designs are more challenging to manufacture and require specialized equipment that is currently uncommon in the industry. However, DOE did not find a reasonable basis to screen this technology option out of the analysis, and is aware of at least one manufacturer producing dry-type symmetric core designs commercially in the United States.
For the preliminary analysis, DOE lacked the data necessary to perform a thorough engineering analysis of symmetric core designs. To generate a cost-efficiency relationship for symmetric core design transformers, DOE made several assumptions. DOE adjusted its traditional core design models to simulate the cost and efficiency of a comparable symmetric core design. To do this, DOE reduced core losses and core weight while increasing labor costs to approximate the symmetric core designs. These adjustments were based on data received from manufacturers, published literature, and through conversations with manufacturers. Table IV.3 indicates the range of potential adjustments for each variable that DOE considered and the mean value used in the analysis.
DOE applied the adjustments to each of the traditional three-phase transformer designs to develop a cost-efficiency relationship for symmetric core technology. DOE did not model a tertiary winding for the wye-wye connected liquid-immersed design lines (DLs). Based on its research, DOE believes that the losses associated with the tertiary winding may offset the benefits of the symmetric core design and that the tertiary winding will add cost to the design. Therefore, DOE modeled symmetric core designs for the three-phase liquid-immersed design lines without a tertiary winding to examine the impact of symmetric core technology on the subgroup of applications that do not require the tertiary winding.
DOE attempts to consider all designs that are technologically feasible and practicable to manufacture and believes that symmetric core designs can meet these criteria. However, DOE was not able to obtain or produce sufficient data to modify its analysis of symmetric cores after the preliminary analysis. For this reason, DOE did not consider symmetric core designs as part of the NOPR analysis.
In response to the NOPR, several manufacturers expressed support for excluding symmetric core designs from DOE's analysis. ComEd, EEI, Progress Energy, NRECA, and APPA all commented that they were pleased to see symmetric core designs excluded from the NOPR analysis. (ComEd, No. 184 at p. 11; EEI, No. 185 at p. 9; APPA, No. 191 at p. 9; PE, No. 192 at p. 7; NRECA, No. 172 at p. 7) BG&E recommended that symmetric core designs not be included in the final rule based on previous comments that highlighted significant issues with the proposed designs. (BG&E, No. 182 at p. 5) Cooper Power pointed out that symmetric core designs have not proven themselves in the market place, and therefore should be excluded in terms of their technological feasibility. (Cooper, No. 165 at p. 4) Similarly, Prolec-GE saw many issues with the use of symmetric core in medium-voltage liquid-filled transformers, and did not believe that this technology offered benefits. (Prolec-GE, No. 177 at p. 10)
ABB and NEMA both observed that any information regarding symmetric core technology for distribution transformers is currently considered strategic and proprietary and cannot be entered into the public record at this time. (ABB, No. 158 at p. 7) NEMA argued further that while it is important for DOE to understand the potential of emerging technologies, such technologies should not be introduced into the regulation until they have proven themselves in the marketplace; symmetric core designs are currently of low penetration in the industry and have not been proven to offer potential for efficiency improvement. (NEMA, No. 170 at p. 11)
Howard Industries commented that symmetric core technology is not appropriate for the majority of the U.S. distribution transformer market, noting that this style of design results in much deeper tanks and larger pads as well as a new winding configuration. It also pointed out that symmetric core designs are patented by Hexaformer AB, in Sweden, and manufacturing this technology requires a license from Hexaformer. Overall, they feel that the cost to adapt to this technology would be large, impractical, and time consuming. (HI, No. 151 at p. 12) Progress Energy Carolinas, Inc. concurred with Howard Industries that the winding configuration for symmetric core designs would be problematic. They pointed out that the delta tertiary winding needed will be subject to thermal failure, and increase the losses of the transformer. Furthermore, they pointed out that the presence of a delta tertiary winding on a wye-wye three-phase distribution transformer will provide a source for zero-sequence currents to ground faults on the source distribution system, resulting in backfeed and, consequently, a potentially hazardous situation. (PE, No. 171 at p. 1)
Finally, Schneider Electric asserted that the efficiency levels proposed in the NOPR are not high enough to lead manufacturers to evaluate symmetric core technology. It commented that, to fully explore these and other technologies, the implementation time and efficiency levels must be increased. It was Schneider Electric's opinion that further, increasing the levels in small increments and only giving four years to transition does not allow for proper research and development to be completed to properly comment on any new technology. (Schneider, No. 180 at p. 5)
In response to the NOPR, DOE did not receive any data that would force reconsideration of the symmetric core analysis conducted during the preliminary analysis. Stakeholders
In setting standards, DOE seeks to analyze the efficiency potentials of commercially available technologies and working prototypes, as well as the availability of those technologies to the market at-large. If certain market participants own intellectual property that enables them to reach efficiencies that other participants practically cannot, amended standards may reduce the competitiveness of the market.
In the case of distribution transformers, stakeholders have raised potential intellectual property concerns surrounding both symmetric core technology and amorphous metals in particular. DOE currently understands that symmetric core technology itself is not proprietary, but that one of the more commonly employed methods of production is the property of the Swedish company Hexaformer AB. However, Hexaformer AB's method is not the only one capable of producing symmetric cores. Moreover, Hexaformer AB and other companies owning intellectual property related to the manufacture of symmetric core designs have demonstrated an eagerness to license such technology to others that are using it to build symmetric core transformers commercially today.
DOE understands that symmetric core technology may ultimately offer a lower-cost path to higher efficiency, at least in certain applications, and that few symmetric cores are produced in the United States. However, DOE notes again that it has been unable to secure data that are sufficiently robust for use as the basis for an energy conservation standard, but encourages interested parties to submit data that would assist in DOE's analysis of symmetric core technology in future rulemakings.
DOE examines a number of core construction techniques in its engineering analysis, including butt-lapping, full mitering, step-lap mitering, and distributed gap wound construction. Particularly in the low-voltage dry-type market, where some smaller manufacturers may not own large mitering machines, core construction methodology is of concern. In the NOPR, DOE did not examine butt-lapped core construction as a design option for design line 7 for steel grades above M6 and, as a result, found only butt-lapped designs are feasible through EL 2. Since the NOPR, however, DOE has reassessed the assumption that butt-lapping is not possible beyond EL 2. For design lines 6 and 8, the topic of butt-lapping is less consequential. All of DOE's design line 6 analysis is centered around butt-lapping,
DOE received several comments on core construction method as it relates to design line 7. During the negotiated rulemaking, ASAP commented that DOE should further explore whether butt-lapping was possible beyond EL 2. (ASAP, No. 146 at p. 135, pp. 25–26) HVOLT, a power and distribution transformer consulting company, commented that butt-lapping could probably get very close to EL 3, but not be the most cost competitive choice at that level. (HVOLT, No. 146 at p. 135) ASAP also commented that DOE should explore more design options in the interest of creating a smoother curve, and that butt-lapped options should be among them. (ASAP, No. 146 at pp. 24–25)
In response to the NOPR, ASAP, two manufacturers of LVDTs, and California Investor-Owned Utilities urged DOE to reconsider the technological assumptions (including butt-lapping capabilities at higher TSLs) behind its TSL 1 proposal. ASAP stated that it believed a more careful consideration of the record and a more thorough investigation of the impacts on small, domestic manufacturers would lead DOE to TSL 3, noting that many manufacturers supported at least TSL 2 during the negotiated rulemaking and believed that TSL 2 could be attained using butt-lapping. (ASAP, No. 186 at pp. 3, 7–8) Eaton generally recommended that DOE standardize efficiency levels to EL 3 (i.e., NEMA Premium®), stating that such efficiency levels are realistic using current technology and are very close to the standards DOE proposed in the NOPR. (Eaton, No. 157 at p. 2) The California IOUs commented that DOE should revise its analysis to reflect that core construction techniques are currently used to produce efficiencies higher than TSL 1 for both small and large manufacturers. (CA IOUs, No. 189 at p. 2) The group of utilities also stated that NEMA lists 11 manufacturers committed to delivering LVDTs at NEMA Premium® efficiency levels, including both large and small manufacturers. (CA IOUs, No. 189 at p. 2) Schneider Electric reiterated its support of efficiency levels higher than those proposed in the NOPR. (Schneider, No. 180 at p. 1)
DOE understands that the ability to produce transformers using a variety of construction techniques is important to preserving design flexibility. After receiving the above-referenced comments on the NOPR, DOE consulted with technical design experts and learned that butt-lapping is technologically feasible for DL 7 through EL 3. DOE revises its understanding of the limits of butt-lapped core construction in today's rule to extend through EL 3 in DL 7.
DOE uses the following four screening criteria to determine which design options are suitable for further consideration in a standards rulemaking:
1.
2.
3.
4.
In the preliminary analysis, DOE identified the technologies for improving distribution transformer efficiency that were under consideration. DOE developed this initial list of design options from the technologies identified in the technology assessment. Then DOE reviewed the list to determine if the
Chapter 4 of the TSD discusses each of these screened-out design options in more detail. The chapter also includes a list of emerging technologies that could impact future distribution transformer manufacturing costs.
DOE is aware that materials science research is being conducted into the use of nanoscale engineering to improve certain properties of materials used in transformers. Nanotechnology is the manipulation of matter on an atomic and molecular scale. Such materials have small-scale structures created through novel manufacturing techniques that may give rise to improved properties (e.g., higher resistivity in steel) not natively present in the bulk material. At present, DOE has not learned of any such materials that meet DOE's criteria of being practicable to manufacture and does not consider nanotechnology composites in its engineering analysis.
Many stakeholders were supportive of DOE's decision to exclude nanotechnology from their analysis in the NOPR. Howard Industries and Cooper Power both expressed that nanotechnology is not a proven technology in the field of distribution transformers; nanotechnology is still in the research phase and further development would be required prior to being viable in the distribution transformer field. (HI, No. 151 at p. 12; Cooper, No. 165 at p. 4) Prolec-GE agreed, pointing out that this technology is “still in its infancy and there is not enough public information to make a practicable analysis if benefits exist.” (Prolec-GE, No. 177 at p. 11) While NRECA, EEI and APPA all expressed interest in the development of advanced technologies that could result in more efficient transformers, they agree with the above stakeholders that this technology is not currently available for distribution transformers. (NRECA, No. 172 at p. 7; APPA, no. 191 at p. 9; EEI, No. 185 at p. 9; BG&E, No. 182 at p. 5) ComEd and Progress Energy noted that, due to lack of availability, nanotechnology composites should not be included in DOE's final rule. (ComEd, No. 184 at p. 11; PE, No. 192 at p. 7)
Stakeholders also noted that information on nanotechnology is not currently readily available. ABB pointed out that any information regarding the application and design of nanotechnology in distribution transformers is considered strategic and proprietary and that these composites are not currently commercially available in the distribution transformer market. (ABB, No. 158 at p. 7) NEMA agreed, stating, “this technology is in its infancy. Information regarding an individual manufacturer's application of this technology is considered strategic and proprietary and cannot be divulged in the public record at this time.” (NEMA, No. 170 at p. 11)
DOE understands that the nanotechnology field is actively researching ways to produce bulk material with desirable features on a molecular scale. Some of these materials may have high resistivity, high permeability, or other properties that make them attractive for use in electrical transformers. DOE knows of no current commercial efforts to employ these materials in distribution transformers and no prototype designs using this technology. Therefore, DOE does not consider nanotechnology composites in the today's rulemaking.
The engineering analysis develops cost-efficiency relationships for the equipment that are the subject of a rulemaking by estimating manufacturer costs of achieving increased efficiency levels. DOE uses manufacturing costs to determine retail prices for use in the LCC analysis and MIA. In general, the engineering analysis estimates the efficiency improvement potential of individual design options or combinations of design options that pass the four criteria in the screening analysis. The engineering analysis also determines the maximum technologically feasible (“max-tech”) energy efficiency level.
DOE must consider those distribution transformers that are designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy determines to be technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) Therefore, an important role of the engineering analysis is to identify the maximum technologically feasible efficiency level. The maximum technologically feasible level is one that can be reached by adding efficiency improvements and/or design options, both commercially feasible and in prototypes, to the baseline units. DOE believes that the design options comprising the maximum technologically feasible level must have been physically demonstrated in a prototype form to be considered technologically feasible.
In general, DOE can use three methodologies to generate the manufacturing costs needed for the engineering analysis. These methods are:
(1) The design-option approach—reporting the incremental costs of adding design options to a baseline model;
(2) the efficiency-level approach—reporting relative costs of achieving improvements in energy efficiency; and
(3) the reverse engineering or cost assessment approach—involving a “bottom up” manufacturing cost
DOE's analysis for this rulemaking is based on the design-option approach, in which design software is used to assess the cost-efficiency relationship between various design option combinations. This is the same approach that was taken in the 2007 final rule for distribution transformers.
When developing its engineering analysis for distribution transformers, DOE divided the covered equipment into equipment classes. As discussed, distribution transformers are classified by insulation type (liquid immersed or dry type), number of phases (single or three), primary voltage (low voltage or medium voltage for dry-type distribution transformers) and basic impulse insulation level (BIL) rating (for dry types). Using these transformer design characteristics, DOE developed ten equipment classes. Within each of these equipment classes, DOE further classified distribution transformers by their kilovolt-ampere (kVA) rating. These kVA ratings are essentially size categories, indicating the power handling capacity of the transformers. For DOE's rulemaking, there are over 100 kVA ratings across all ten equipment classes.
DOE recognized that it would be impractical to conduct a detailed engineering analysis on all kVA ratings, so it sought to develop an approach that simplified the analysis while retaining reasonable levels of accuracy. DOE consulted with industry representatives and transformer design engineers to develop an understanding of the construction principles for distribution transformers. It found that many of the units share similar designs and construction methods. Thus, DOE simplified the analysis by creating engineering design lines (DLs), which group kVA ratings based on similar principles of design and construction. The DLs subdivide the equipment classes in order to improve the accuracy of the engineering analysis. These DLs differentiate the transformers by insulation type (liquid immersed or dry type), number of phases (single or three), and primary insulation levels for medium-voltage dry-type distribution transformers (three different BIL levels).
After developing its DLs, DOE then selected one representative unit from each DL for study, greatly reducing the number of units for direct analysis. For each representative unit, DOE generated hundreds of unique designs by contracting with Optimized Program Services, Inc. (OPS), a software company specializing in transformer design since 1969. The OPS software used three primary inputs that it received from DOE: (1) A design option combination, which included core steel grade, primary and secondary conductor material, and core configuration; (2) a loss valuation combination; and (3) material prices. For each representative unit, DOE examined anywhere from 8 to 16 design option combinations and for each design option combination, the OPS software generated 518 designs based on unique loss valuation combinations. These loss valuation combinations are known in industry as A and B evaluation combinations and represent a customer's present value of future losses in a transformer core and winding, respectively. For each design option combination and A and B combination, the OPS software generated an optimized transformer design based on the material prices that were also part of the inputs. Consequently, DOE obtained thousands of transformer designs for each representative unit. The performance of these designs ranged in efficiency from a baseline level, equivalent to the current distribution transformer energy conservation standards, to a theoretical max-tech efficiency level.
After generating each design, DOE used the outputs of the OPS software to help create a manufacturer selling price (MSP). The material cost outputs of the OPS software, along with labor estimates, were marked up for scrap factors, factory overhead, shipping, and non-production costs to generate a MSP for each design. Thus, DOE obtained a cost versus efficiency relationship for each representative unit. Finally, after DOE had generated the MSPs versus efficiency relationship for each representative unit, it extrapolated the results to the other, unanalyzed, kVA ratings within that same engineering design line.
PEMCO commented that DOE generated too many designs, and that many were impractical or unlikely to sell. (PEMCO, No. 183 at p. 1) EMS Consulting made an opposite remark, that DOE's chosen methodology omits many possible solutions. (EMS, No. 178 at p. 5) Finally, NEMA commented that the “steepness” of some of DOE's curves were lower than was shown by some manufacturers, ABB in particular. (NEMA, No. 170 at p. 4, p. 3) In other words, NEMA questioned whether cost might rise more quickly with efficiency than DOE's analysis suggested. Conversely, ATI Allegheny commented that DOE did excellent work on the engineering analysis. (ATI, No. 181 at p. 1)
DOE acknowledges both that it may not have analyzed every possible design and that, conversely, some designs would be unlikely to be considered by many purchasers, but notes that the goal of the engineering analysis is to both explore the limits of design possibility and establish a cost/efficiency behavior. The Life-Cycle Cost and Payback Period Analysis, in turn, examines which of the designs would be cost-effective for individual purchasers. It would not be practical to attempt to analyze every possible physical design. Regarding NEMA's comments, DOE is always seeking constructive feedback to aid in the accuracy of its engineering analysis, but cautions that comparisons between designs must be made carefully in order to be sure that they remain valid across a wide variety of market forces and construction techniques. A manufacturer's cost of producing higher-efficiency units in today's market may be different than the cost of meeting those same efficiencies after establishment of energy conservation standards, which may lead to production at higher volumes.
For the preliminary analysis, DOE analyzed 13 DLs that cover the range of equipment classes within the distribution transformer market. Within each DL, DOE selected a representative unit to analyze in the engineering analysis. A representative unit is meant to be an idealized unit typical of those used in high volume applications.
In view of comments received from stakeholders throughout the analysis period, DOE slightly modified its representative units for the NOPR analysis. For the NOPR, DOE analyzed the same 13 representative units as in the preliminary analysis, but also added a design line, and therefore representative unit, by splitting the former design line 13 into two new design lines, 13A and 13B. This new representative unit allows DOE's analysis to better reflect the behavior of high kVA, high BIL medium-voltage dry-type units and is shown in Table IV.5. The representative units selected by DOE were chosen because they comprise high volume segments of the market for their respective design lines and also provide, in DOE's view, a reasonable basis for scaling to the unanalyzed kVA ratings. DOE chooses certain designs to analyze as representative of a particular design line or design lines because it is impractical to analyze all possible designs in the scope of coverage for this rulemaking.
There are many different combinations of design options that could be considered for each representative unit DOE analyzes. While DOE cannot consider all the possible combinations of design options, DOE attempts to select design option combinations that are common in the industry while also spanning the range of possible efficiencies for a given DL. For each design option combination chosen, DOE evaluates 518 designs based on different A and B factor
For the preliminary analysis, DOE considered a design option combination that uses an amorphous steel core for each of the dry-type design lines, whereas DOE's 2007 final rule did not consider amorphous steel designs for the dry-type design lines. Instead, DOE had considered H–0 domain refined (H–0 DR) steel as the maximum-technologically feasible design. However, DOE is aware that amorphous steel designs are now used in dry-type distribution transformers. Therefore, DOE considered amorphous steel designs for each of the dry-type transformer design lines in the preliminary analysis.
During preliminary interviews with manufacturers, DOE received comment that it should consider additional design option combinations using aluminum for the primary conductor rather than copper. While manufacturers commented that copper is still used for the primary conductor in many distribution transformers, they noted that aluminum has become relatively more common. This is due to the relative prices of copper and aluminum. In recent years, copper has become even more expensive compared to aluminum.
DOE also noted that certain design lines were lacking a design to bridge the efficiency values between the lowest efficiency amorphous designs and the next highest efficiency designs. In an effort to close that gap for the preliminary analysis, DOE evaluated ZDMH and M2 core steel as the highest efficiency designs below amorphous for the liquid-immersed design lines. Similarly, DOE evaluated H–0 DR and M3 core steel as the highest efficiency designs below amorphous for dry-type design lines.
DOE incorporated these supplementary designs into the reference case (i.e., DOE's default set of assumptions without any sensitivity analysis) for the NOPR analysis. Additionally, DOE aimed to consider the most popular design option combinations, and the design option combinations that yield the greatest improvements in efficiency. While DOE was unable to consider all potential design option combinations, it did consider multiple designs for each representative unit and considered additional design options in its NOPR analysis based on stakeholder comments.
As for wound core designs, DOE did consider analyzing them for all of its dry-type representative units that are
DOE did not consider wound core designs for DLs 10, 12, and 13B because they are 1500 kVA and larger. DOE understands that conventional wound core designs in these large kVA ratings will emit an audible “buzzing” noise, and will experience an efficiency penalty that grows with kVA rating such that stacked core is more attractive. DOE notes, however, that it does consider a wound core amorphous design in each of the dry-type design lines.
DOE did opt to add two design option combinations that incorporate M-grade steels that have become popular choices at the current standard levels. For all medium-voltage dry-type design lines (9–13B), DOE added a design option combination of an M4 step-lap mitered core with aluminum primary and secondary windings. For design line 8, DOE added a design option combination of an M6 fully mitered core with aluminum primary and secondary windings. DOE understands both combinations to be prevalent baseline options in the present transformer market.
For the NOPR analysis, DOE also made the decision to remove certain high flux density designs from DL7 to be consistent with designs submitted by manufacturers.
In response to the NOPR, Eaton noted that this rule provides many design options, and allows for the use of various designs and different grades of steel, but encouraged DOE to standardize the efficiency levels to NEMA Premium® (i.e., EL 3). (Eaton, No. 157 at p. 2) Although Schneider supported the LVDT efficiency levels proposed by DOE in the NOPR, the company stated in its NOPR comments that it still supports efficiency levels higher than those proposed in the NOPR (as evidenced by discussions during the negotiated rulemaking meetings.) (Schneider, No. 180 at p. 1)
ASAP commented that it perceived there to be a “gap” in the DL 7 data, and that DOE should seek to fill that gap by exploring other design option combinations corresponding to butt-lapped core construction. (ASAP, No. 146 at p. 24–25, 135) In response, DOE first generated analysis for two additional design option combinations: An M4 core with aluminum windings and an M3 core with copper windings. DOE includes both sets of results in its final rule engineering analysis. In general, DOE notes that preservation of a number of design options was a strong consideration in selection of the final standard. Second, given these two new design lines discussed above, DOE revisited the question of whether DL 7 for LVDTs was achievable by manufacturers with butt lapping techniques in order to avoid purchasing mitering equipment. Specifically, DOE consulted with technical design experts, and they confirmed butt-lapping was technically feasible through EL 3. In addition, as detailed in section IV.A.3, DOE received public comment supporting this conclusion and did not receive public comments directly refuting this conclusion. (See, e.g., ASAP, No. 186 at pp. 3, 7–8; Eaton, No. 157 at p. 2; CA IOUs, No. 189 at p. 2)
Consequently, DOE modified the LVDT standard proposed from TSL 1 to TSL 2 in today's final rule.
DL 7 analysis illustrating the possibility of constructing butt-lapped cores at EL3 led DOE to reconsider the impacts to small manufacturers. DOE originally assumed that a small manufacturer without the equipment needed to construct mitered cores would have to either invest in such equipment at considerable expense, source cores from a third party, or exit that market. As explained in Section IV.I.1, DOE calculates the net present value of the industry (“INPV”) in attempting to quantify impacts to manufacturers under different scenarios. During the NOPR, DOE calculated LVDT INPV to be between $200 million and $235 million (in 2011$). In today's final rule, that figure rises to $227 million to $249 million (in 2011$).
In addition, as described in the NOPR and as DOE confirmed for the final rule, DOE understands that the majority of the LVDT market volume is currently imported, much of it from large, well-capitalized manufacturers in Mexico. Furthermore, many small businesses operating inside the United States cater to niches outside of DOE's scope of coverage, and would not be directly affected by the rule. Finally, DOE spoke with several small domestic manufacturers and learned that some are already able to miter cores, and would make the decision to butt-lap or miter at EL3 based on economics and without facing large capital investment decisions. More detail can be found in Section IV.I.5.b.
As discussed, one of the primary inputs to the OPS software is an A and B combination for customer loss evaluation. In the preliminary analysis, DOE generated each transformer design in the engineering analysis based upon an optimized lowest total owning cost evaluation for a given combination of A and B values. Again, the A and B values represent the present value of future core and coil losses, respectively and DOE generated designs for over 500 different A and B value combinations for each of the design option combinations considered in the analysis.
DOE notes that the designs created in the engineering analysis span a range of costs and efficiencies for each design option combination considered in the analysis. This range of costs and efficiencies is determined by the range of A and B factors used to generate the designs. Although DOE does not generate a design for every possible A and B combination, because there are infinite variations, DOE believes that its 500-plus combinations have created a sufficiently broad design space. By using so many A and B factors, DOE is confident that it produces the lowest first cost design for a given efficiency level and also the lowest total owning cost design. Furthermore, although all distribution transformer customers do not purchase based on total owning cost, the A and B combination is still a useful tool that allows DOE to generate a large number of designs across a broad range of efficiencies and costs for a particular design line. Finally, OPS noted at the public meeting that its design software requires A and B values as inputs. (OPS, Pub. Mtg. Tr., No. 34 at p. 123) For all of these reasons, DOE continued to use A and B factors from the NOPR to generate the range of designs for the final rule engineering analysis.
In distribution transformers, the primary materials costs come from electrical steel used for the core and the aluminum or copper conductor used for
DOE decided to use current (2010) materials prices in its analysis for the preliminary analysis because of feedback from manufacturers during interviews. Manufacturers noted the difficulty in choosing a price that accurately projects future materials prices due to the recent variability in these prices. Manufacturers also commented that the previous five years had seen steep increases in materials prices through 2008, after which prices declined as a result of the global economic recession. Further detail on these factors can be found in appendix 3A. Due to the variability in materials prices over this five-year timeframe, manufacturers did not believe a five-year average price would be the best indicator, and recommended using the current materials prices.
To estimate its materials prices, DOE spoke with manufacturers, suppliers, and industry experts to determine the prices paid for each raw material used in a distribution transformer in each of the five years between 2006 and 2010. While prices fluctuate during the year and can vary from manufacturer to manufacturer depending on a number of variables, such as the purchase quantity, DOE attempted to develop an average materials price for the year based on the price a medium to large manufacturer would pay.
With the onset of the negotiations, DOE was presented with an opportunity to implement a 2011 materials price case based on data it had gathered before and during the negotiation proceedings. Relative to the 2010 case, the 2011 prices were lower for all steels, particularly M2 and lower grade steels.
For the NOPR, DOE reviewed its materials prices during interviews with manufacturers and industry experts and revised its materials prices for copper and aluminum conductors. DOE derived these prices by adding a processing cost increment to the underlying index price. DOE determined the current 2011 index price from the LME and COMEX, two well-known commodities benchmarks. These indices only had current 2011 values available, so DOE used the producer price index for copper and aluminum to convert the 2011 index price into prices for the time period of 2006–2010. DOE then applied a unique processing cost adder to the index price for each of its conductor groupings. To derive the adder price, DOE compared the difference in the LME index price to the 2011 price paid by manufacturers, and applied this difference to the index price in each year. DOE inquired with many manufacturers, both large and small, to derive these prices. Materials price cases for the final rule are identical to those of the NOPR. Further detail can be found in chapter 5 of the TSD.
DOE reviewed core steel prices with manufacturers and industry experts and found them to be accurate within the range of prices paid by manufacturers in 2010. However, based on feedback in negotiations, DOE adjusted steel prices for M4 grade steels and lower grade steels.
Several stakeholders commented on the material prices used in the NOPR. ABB, NRECA, and NEMA all noted that the material costs appeared to be too low, both for 2010 and 2011. (ABB, No. 158 at pp. 7–8; NEMA, No. 170 at p. 11; NRECA, No. 146 at p. 159) Similarly, Prolec-GE pointed out that, as the economy recovers, demand for these materials will increase, as will their prices. They agreed that DOE's material price projections were too low. (Prolec-GE, No. 177 at p. 11) ATI specifically noted that DOE's price for M3 steel was too low in the 2011 price scenario, and commented that this price is a very important one in the analysis. (ATI, No. 146 at pp. 74–75) Progress Energy concurred, noting that the price of silicon core steel in DOE's analysis was lower than actual prices, and recommended that DOE revise all their material prices. (PE, No. 192 at p. 7) Cooper and HI agreed with these stakeholders that DOE's material prices were too low, specifically pointing out that surcharges need to be included to more accurately reflect real world prices. (Cooper, No. 165 at p. 4; HI, No. 151 at p. 12)
APPA did not disagree with DOE's material prices, but pointed out that if DOE choose to update them, they should update wholesale electric prices to the most recent year available as well. (APPA, No. 191 at p. 9) BG&E and ComEd agreed, pointing out “base costs, for both material and wholesale energy, should reflect from the most recent published data for the most recent year.” (BG&E No. 182 at p. 5; ComEd, No. 184 at p. 11) ASAP commented that DOE should re-optimize its engineering analysis with respect to the new pricing to find the most accurate results. (ASAP, No. 146 at p. 153)
DOE notes that because it analyzes such a large breadth of designs, its engineering analysis is less sensitive to changes in materials prices than it otherwise would be. DOE performed a sensitivity analysis during the preliminary analysis phase of the rulemaking in order to understand the magnitude of the effect of a change in material prices and found it to be very small. The differential pricing between the designs, upon which the LCC, NIA, and other economics results are based, are even less sensitive. DOE believes its conclusions would not vary between either case.
DOE appreciates the above-listed feedback from commenters, however, for today's rule, DOE continues to use the 2010 and 2011 materials prices that were first included in the NOPR as reference case scenarios, which is the most recent and accurate information available to DOE. DOE presents both cases as recent examples of how the steel market fluctuates and uses both to derive economic results. It also considered high and low price scenarios based on the 2008 and 2006 materials prices, respectively, but adjusted the prices in each of these years to consider greater diversity in materials prices. For the high price scenario, DOE increased the 2008 prices by 25 percent, and for the low price scenario, DOE decreased the 2006 prices by 25 percent as additional sensitivity analyses. DOE believes that these price sensitivities accurately account for any pricing discrepancies experienced by smaller or larger manufacturers, and adequately consider potential price fluctuations.
For the engineering analysis, DOE did not attempt to forecast future materials prices. DOE continued to use the 2010 materials price in the reference case scenario, added a 2011 reference scenario, and also considered high and low sensitivities to account for any potential fluctuations in materials prices. The LCC and NIA consider a scenario, however, in which transformer prices increase in the future based on increasing materials prices, among other variables. Further detail on this scenario can be found in chapter 8 of the TSD.
DOE derived the manufacturer's selling price for each design in the
DOE interviewed manufacturers of distribution transformers and related products to learn about markups, among other topics, and observed a number of very different practices. In absence of a consensus, DOE attempted to adapt manufacturer feedback to inform its current modeling methodology while acknowledging that it may not reflect the exact methodology of many manufacturers. DOE feels that it is necessary to model markups, however, since there are costs other than material and labor that affect final manufacturer selling price. The following sections describe various facets of DOE's markups for distribution transformers.
DOE uses a factory overhead markup to account for all indirect costs associated with production, indirect materials and energy use (e.g., annealing furnaces), taxes, and insurance. In the preliminary analysis, DOE derived the cost for factory overhead by applying a 12.5 percent markup to direct material production costs.
In the preliminary analysis, DOE applied the same factory overhead markup to its prefabricated amorphous cores as it did to its other design options where the manufacturer was assumed to produce the core. Since the factory overhead markup accounts for indirect production costs that are not easily tied to a particular design, it was applied consistently across all design types. DOE did not find that there was sufficient substantiation to conclude that manufacturers would apply a reduced overhead markup for a design with a prefabricated core.
For today's rule, DOE continued to apply the same factory overhead markup to prefabricated amorphous cores as to other cores built in-house. This approach is consistent with the suggestion of the manufacturers, and DOE notes that factory overhead for a given design applies to many items aside from the core production. Furthermore, since DOE already accounts for decreased labor hours in its designs using prefabricated amorphous cores, but also considers an increased core price based on a prefabricated core rather than the raw amorphous material, it already accounts for the tradeoffs associated with developing the core in-house versus out-sourced.
During negotiations, DOE learned from both manufacturers of transformers and manufacturers of transformer cores that mitering and, to a greater extent, step-lap mitering result in a per-pound cost of finished cores higher than the per-pound cost of butt-lapped units built to the same specifications. (ONYX, Pub. Mtg. Tr., No. 30 at p. 43) In view of the manufacturer comments, DOE understands that butt-lapping is common at baseline efficiencies in today's low-voltage market.
In response, DOE opted to increase mitering costs for both low- and medium-voltage dry-type designs. In the medium-voltage case, DOE incorporated a processing cost of 10 cents per core pound for step-lap mitering. In the low-voltage case, DOE incorporated a processing cost of 10 cents per core pound for ordinary mitering and 20 cents per core pound for step-lap mitering. DOE used different per pound adders for step-lap mitering for medium-voltage and low-voltage units because the base case design option for each is different. For low-voltage units, DOE modeled butt-lapped designs at the baseline efficiency level whereas ordinary mitering was modeled at the baseline for medium-voltage. Therefore, using a step-lap mitered core represents a more significant change in technology for low-voltage dry-type transformers than for medium-voltage transformers, necessitating higher markup.
In the preliminary analysis, DOE accounted for additional labor and material costs for large (≥1500 kVA), dry-type designs using amorphous metal. The additional labor costs accounted for special handling considerations, since the amorphous material is very thin and can be difficult to work with in such a large core. They also accounted for extra bracing that is necessary for large, wound core, dry-type designs in order to prevent short circuit problems.
In response to interested party feedback, DOE applied an incremental increase in core assembly time to amorphous designs in the liquid-immersed design line 5 (1500 kVA). This additional core assembly time of 10 hours is consistent with DOE's treatment of amorphous designs in large, dry-type design lines. However, DOE did not account for additional hardware costs for bracing in the liquid-immersed designs using amorphous cores. This is because DOE already accounts for bracing costs for all of its liquid-immersed designs, which use wound cores, in its analysis. DOE determined that it adequately accounted for these bracing costs in the smaller kVA sizes using amorphous designs, and thus only made the change to the large (≥1500 kVA) design lines. DOE did not model varying incremental cost increases starting with zero for large amorphous designs, as the Northwest Energy Efficiency Alliance (NEEA) and Northwest Power and Conservation Council (NPCC) suggested, noting that the impact of these incremental costs are often very minor for large, expensive transformer designs. (NEEA, No. 11 at p. 7) Following discussion with Federal Pacific and other manufacturers of medium- and low-voltage transformers, DOE explored its estimates of labor hours and increased those relating to core assembly for design lines 6–13B. Details on the specific values of the adjustments can be found in chapter 5 of the TSD.
During its interviews with manufacturers in the preliminary analysis, DOE was informed that manufacturers often pay shipping (freight) costs to the customer. Manufacturers indicated that they absorb the cost of shipping the units to the customer and that they include these costs in their total cost structure when calculating profit markups. As such, manufacturers apply a profit markup to their shipping costs just like any other cost of their production process. Manufacturers indicated that these costs typically amount to anywhere from four to eight percent of revenue.
In the 2007 final rule, DOE accounted for shipping costs exclusively in the LCC analysis. These costs were paid by the customer, and thus did not include a markup from the manufacturer based on its profit factor. In the preliminary analysis, DOE included shipping costs in the manufacturer's cost structure, which is then marked up by a profit
For the NOPR, DOE revised its shipping cost estimate to account for the rising cost of diesel fuel. DOE adjusted its previous shipping cost of $0.20 (in 2006 dollars) from the 2007 final rule to a 2011 cost based on the producer price index for No. 2 diesel fuel. This yielded a shipping cost of $0.28 per pound. DOE also retained its shipping cost calculation based on the weight of the transformer to differentiate the shipping costs between lighter and heavier, typically more efficient, designs.
In the preliminary analysis, DOE applied a non-production markup to all cost components, including shipping costs, to derive the MSP. DOE based this cost treatment on the assumption that manufacturers would mark up the shipping costs when calculating their final selling price. The resulting shipping costs were, as stated, approximately four to eight percent of total MSP.
Based on comments received and DOE's additional research into the treatment of shipping costs through manufacturer interviews, DOE decided to retain the shipping costs in its calculation of MSP, but not to apply any markups to the shipping cost component. Therefore, shipping costs were added separately into the MSP calculation, but not included in the cost basis for the non-production markup. The resulting shipping costs were still in line with the estimate of four to eight percent of MSP for all the dry-type design lines. For the liquid-immersed design lines, the shipping costs ranged from six to twelve percent of MSP and averaged about nine percent of MSP. This practice was retained for the final rule.
DOE analyzed designs over a range of efficiency values for each representative unit. Within the efficiency range, DOE developed designs that approximate a continuous function of efficiency. However, DOE only analyzes incremental impacts of increased efficiency by comparing discrete efficiency benchmarks to a baseline efficiency level. The baseline efficiency level evaluated for each representative unit is the existing energy conservation standard level of efficiency for distribution transformers established either in DOE's 2007 final rule for medium-voltage transformers or by EPACT 2005 for low-voltage transformers. The incrementally higher efficiency benchmarks are referred to as “efficiency levels” (ELs) and, along with MSP values, characterize the cost-efficiency relationship above the baseline.
For today's rule, DOE considered several criteria when setting ELs. First, DOE harmonized the efficiency values across single-phase transformers and the per-phase kVA equivalent three-phase transformers. For example, a 50 kVA single-phase transformer would have the same efficiency requirement as a 150 kVA three-phase transformer. This approach is consistent with DOE's methodology from the 2007 final rule and from the preliminary analysis of this rulemaking. Therefore, DOE selected equivalent ELs for several of the representative units that have equivalent per-phase kVA ratings.
Second, DOE selected equally spaced ELs by dividing the entire efficiency range into five to seven evenly spaced increments. The number of increments depended on the size of the efficiency range. This allowed DOE to examine impacts based on an appropriate resolution of efficiency for each representative unit.
Finally, DOE adjusted the position of some of the equally spaced ELs and examined additional ELs. These minor adjustments to the equally spaced ELs allowed DOE to consider important efficiency values based on the results of the software designs. For example, DOE adjusted some ELs slightly up or down in efficiency to consider the maximum efficiency potential of non-amorphous design options. Other ELs were added to consider important benchmark efficiencies, such as the NEMA Premium® efficiency levels for LVDT distribution transformers. Last, DOE considered additional ELs to characterize the maximum-technologically feasible design for representative units where the harmonized per-phase efficiency value would have been unachievable for one of the representative units.
Although DOE's current test procedure specifies a load value at which to test transformers, DOE recognizes that different consumers see real-world loadings that may be higher or lower. In those cases, consumers may choose a transformer offering a lower LCC even when faced with a higher first cost. If DOE's cost/efficiency design cloud were redrawn to reflect loadings other than those specified in the test procedure, different designs would migrate to the optimum frontier of the cloud. Additionally, although DOE's engineering analysis reflects a range of transformers costs for a given EL, the LCC analysis only selects transformer designs near the lowest cost point.
For today's rule, DOE performed a detailed analysis on each representative unit and then extrapolated the results of its analysis from the unit studied to the other kVA ratings within that same engineering design line. DOE performed this extrapolation to develop inputs to the national impacts analysis. The technique it used to extrapolate the findings of the representative unit to the other kVA ratings within a design line is referred to as “the 0.75 scaling rule.” This rule states that, for similarly designed transformers, costs of construction and losses scale with the ratio of their kVA ratings raised to the 0.75 power. The relationship is valid where the optimum efficiency loading points of the two transformers being scaled are the same. DOE used the same methodology to scale its findings during the 2007 final rule on distribution transformers.
Because it is not practical to directly analyze every combination of design options and kVAs under the rulemaking's scope of coverage, DOE selected a smaller number of units it believed to be representative of the larger scope. Many of the current design lines use representative units retained from the 2007 final rule with minor modifications. To generate efficiency values for kVA values not directly analyzed, DOE employed a scaling methodology based on physical principles (overviewed in Appendix 5B) and widely used by industry in various forms. DOE's scaling methodology is an approximation and, as with any approximation, can suffer in accuracy as it is extended further from its reference value.
Additionally, DOE modified the way it splices extrapolations from each representative unit to cover equipment classes at large. Previously, DOE extrapolated curves from individual data points and blended them near the boundaries to set standards. Currently, DOE fits a single curve through all available data points in a space and believes that the resulting curve is smoother and offers a more robust scaling behavior over the covered kVA range.
DOE received a number of comments on the matter of scaling across kVA ranges. Cooper Power Systems supported the use of the .75 exponent, though noted that it may not hold for higher kVA values. (Cooper, No. 165 at p. 4) MGLW commented that for single-phase pad-mounted distribution transformers the exponent may approach .75, but that it was not accurate for single-phase pole-mounted distribution transformers, whose curve would be of polynomial form. (MLGW, No. 127 at p. 1) PEMCO proposed to use a curve in logarithmic space, which would create an even more complex behavior in linear coordinates. (PEMCO, No. 183 at p. 2) Progress Energy commented that DOE should avoid scaling altogether, and instead use data from vendors. (PE, No. 192 at p. 6) ABB, APPA, BG&E, EEI, Howard, NEMA, NRECA, Power Partners, Prolec-GE, Commonwealth Edison, and Schneider all commented that DOE's general approach was sound, but that the accuracy of the procedure may be improved with more data-validated modeling. (ABB, No. 158 at p. 7; APPA, No. 191 at pp. 7–8; APPA, No. 237 at p. 3; BG&E, No. 182 at p. 5; EEI, No. 185 at p. 9; HI, No. 151 at p. 12; NEMA, No. 170 at p. 10; NRECA, No. 172 at p. 6; Power Partners, No. 155 at p. 3; Prolec-GE, No. 146 at pp. 82–83; Prolec-GE, No. 177 at p. 10; ComEd, No. 184 at p. 10; Schneider, No. 180 at p. 5)
In the case of equipment class 1, which addresses single-phase liquid-immersed distribution transformers, some stakeholders expressed confusion on the scaling. Because this equipment class contains three design lines and because DOE is deriving a standard using a straight line in logarithmic space, it is possible that the three ELs, one from each design line) may not fall exactly in-line. In that case, as occurred for equipment class one with TSL 1, DOE best fit a straight line through three points. APPA, EEI, Berman Economics, NRECA, Pepco, and the Advocates both commented that because DOE did not propose a standard that aligned with each of these ELs, the economic results were not exact. (APPA, No. 191 at p. 3; Berman Economics, No. 150 at p. 2; NRECA, No. 2; Pepco, No. 145 at pp. 1–2; Advocates, No. 186 at pp. 9–10) DOE thanks the commenters for making that clear, and has revised its presentation of final rule economic results accordingly.
For today's rule, DOE finds the NOPR methodology well-supported by a large number of stakeholders and continues to employ it. DOE believes transformers are approximately well-modeled as power-law devices. In other words, attributes of the devices should grow in proportion to the size raised to a constant power. The ideal, mathematically derived value of that exponent is .75, but in practice transformers may not be constructed ideally and other effects may drive the exponent above or below .75. DOE believes allowing the exponent to float from .75 where justified may help to account for certain size-dependent effects not always well captured by the theoretical .75 result.
In the 2007 final rule, DOE covered both single- and three-phase transformers and harmonized standards across phases. More specifically, DOE set standards such that a single-phase transformer of a certain type (e.g., liquid immersed) and kVA rating (e.g., 100) would be required to meet the same standard as would a three-phase transformer of the same type and three times the kVA rating (in this example, 300 kVA liquid immersed). In certain cases, DOE believes there is sound technological basis for doing so. For example, three-phase liquid-immersed distribution transformers mounted on poles are frequently constructed using three single-phase cores inside of a single housing. Although miscellaneous losses may vary slightly (e.g., bus losses) across three- and single-phase pole-mounted units, one would expect the core-and-coil efficiencies to be identical for a similar construction choices such as steel grade, winding grade, core geometry, etc.
In many other cases, however, there may not be a strong technical basis for strongly coupling single- and three-phase standards. Several parties commented on the matter in response to the NOPR.
Howard Industries and Power Partners both supported linking single- and three-phase standards, as was done in the 2007 final rule. (HI, No. 151 at p. 12; Power Partners, No. 155 at p. 3) ABB, APPA, Cooper, NEMA, Progress Energy, Prolec-GE, and Schneider, however, argued that construction differences resulted in there being no logical reason to link the two standards, and that any standards should be derived from independent analysis of each. (ABB, No. 158 at p. 7; APPA, No. 191 at p. 7; Cooper, No. 165 at p. 3; NEMA, No. 170 at p. 10; NEMA, No. 170 at p. 3; PE, No. 192 at p. 6; Prolec-GE, No. 146 at p. 85; Prolec-GE, No. 177 at p. 9; Schneider, No. 180 at p. 5)
In today's rule, DOE follows the convention of the NOPR and does not impose the constraint that single- and three-phase efficiencies must be linked. DOE notes, however, that standards were harmonized across phase counts in the case of single-phase MVDT equipment classes, where market volume is minimal and direct analysis of such units a lower priority.
Throughout this rulemaking, DOE received several comments expressing concern over the availability of materials, including core steel and conductors, needed to build energy efficient distribution transformers. These issues pertain to a global scarcity of materials as well as issues of materials access for small manufacturers.
DOE is aware that many core steels, including amorphous steels, have constraints on their supply and presents an analysis of global steel supply in TSD appendix 3–A.
DOE understands that primary voltage and the accompanying BIL may increasingly affect efficiency of liquid-immersed transformers as standards rise. DOE may conduct primary voltage sensitivity analysis in order to better quantify the effects of BIL and primary voltage on efficiency, and may use such information to consider establishing equipment classes by BIL rating for liquid-immersed distribution transformers.
In the engineering analysis, DOE only considered transformer designs with impedances within the normal impedance ranges specified in Table 1 and Table 2 of 10 CFR 431.192. These impedances represent the typical range of impedance that is used for a given liquid-immersed or dry-type transformer based on its kVA rating and whether it is single-phase or three-phase.
Several stakeholders expressed concern over efficiency standards that could potentially cause changes in impedance. Progress Energy, BG&E, NEMA and ComEd all commented that the increased efficiency levels in the 2010 standards resulted in changes in impedance values. (PE, No. 192 at p. 11;
On the other hand, various stakeholders claimed that there was no direct relationship between impedance and efficiency levels. EEI commented that they would be concerned if higher standards would make it more difficult for manufacturers to meet the necessary requirements for impedance, inrush current and X/R ratio, but noted that they are not currently aware of any existing direct relationship. (EEI, No. 185 at p. 20) Prolec-GE agreed, noting that they did not see any issues with inrush, X/R ratios, or impedance at the levels proposed in the NOPR. (Prolec-GE, No. 177 at p. 16)
For today's rule, DOE continued to consider only designs within the normal impedance ranges used in the preliminary analysis. DOE believes that this demonstrates the possibility of manufacturing a variety of impedances at efficiencies well in excess of those adopted in today's rule. While certain applications may have specifications that are more stringent than these normal impedance ranges, DOE believes that the majority of applications are able to tolerate impedances within these ranges. Since DOE considers a wide array of designs within the normal impedance ranges, it adequately accounts for the cost considerations of higher and lower impedance tolerances. Furthermore, DOE believes the standards under consideration in the NOPR to be of modest enough increase to minimize serious concern with respect to impedance and X/R ratio.
In the preliminary analysis, DOE did not constrain the weight of its designs. DOE accounted for the full weight of each design generated by the optimization software based on its materials and hardware. Similarly, DOE let several dimensional measurements of its designs vary based on the optimal core/coil dimensions plus space factors. However, DOE did hold certain tank and enclosure dimensions constant for its design lines. Most notably, DOE fixed the height dimension on all of its rectangular tank transformers. For each design that had variable dimensions, DOE accounted for the additional cost of installing the unit, where applicable.
For today's engineering analysis, DOE did not restrict its designs based on a limit for size or weight beyond the fixed height measurements it was already considering for the rectangular tank sizes. DOE understands that larger transformers may require additional installation costs such as a new pole change-out or vault expansion. To the extent that it had data on these additional costs, DOE accounted for them in its LCC analysis, as described in section IV.F. However, DOE did not choose to limit its design specifications based on a specific size or weight constraint.
Nonetheless, DOE notes that the majority of its designs are within weight constraints suggested by stakeholders. In design line 2, over 95 percent of DOE's designs are below 650 pounds. In design line 3, over 62 percent of DOE's designs are below 3,600 pounds, and when only the designs with the lowest first cost are considered, nearly 74 percent of the designs are less than 3,600 pounds. The majority of the designs that exceed 3,600 pounds are at the maximum efficiency levels using an amorphous core steel.
DOE worked with manufacturers to explore the magnitude of the effect of longer buses and leads and found it to be small relative to the gap between efficiency levels. Nonetheless, DOE made small upward adjustments to bus and lead losses of all medium-voltage dry-type design lines. Details on the specific values of the adjustments made can be found in chapter 5 of the TSD.
The markups analysis develops appropriate markups in the distribution chain to convert the estimates of manufacturer selling price derived in the engineering analysis to customer prices. In the preliminary analysis, DOE determined the distribution channels for distribution transformers, their shares of the market, and the markups associated with the main parties in the distribution chain, distributors, contractors and electric utilities.
Based on comments from interested parties, for the NOPR DOE added a new distribution channel to represent the direct sale of transformers to utilities, which account for approximately 80 percent of liquid-immersed transformer shipments. Howard Industries and Prolec-GE agreed with DOE's estimate that 80 percent of transformers are sold by manufacturers to utilities. (HI, No. 151 at p. 8; Prolec-GE, No. 177 at p. 13) For the final rule, DOE retained this distribution channel.
DOE developed average distributor and contractor markups by examining the installation and contractor cost estimates provided by
Chapter 6 of the final rule TSD provides additional detail on the markups analysis.
The energy use analysis produced energy use estimates and end-use load shapes for distribution transformers. The energy use estimates enable evaluation of energy savings from the operation of distribution transformer equipment at various efficiency levels, while the end-use load characterization allows evaluation of the impact on monthly and peak demand for electricity.
The energy used by distribution transformers is characterized by two types of losses. The first are no-load losses, which are also known as core losses. No-load losses are roughly constant and exist whenever the transformer is energized (
Because the application of distribution transformers varies significantly by type of transformer (liquid immersed or dry type) and ownership (electric utilities own approximately 95 percent of liquid-immersed transformers; commercial/industrial entities use mainly dry type), DOE performed two separate end-use load analyses to evaluate distribution transformer efficiency. The analysis for liquid-immersed transformers assumes that these are owned by utilities and uses hourly load and price data to estimate the energy, peak demand, and cost impacts of improved efficiency. For dry-type transformers, the analysis assumes that these are owned by commercial and industrial customers, so the energy and cost savings estimates are based on monthly building-level demand and energy consumption data and marginal electricity prices. In both cases, the energy and cost savings are estimated for individual transformers and aggregated to the national level using weights derived from either utility or commercial/industrial building data.
For utilities, the cost of serving the next increment of load varies as a function of the current load on the system. To correctly estimate the cost impacts of improved transformer efficiency, it is therefore important to capture the correlation between electric system loads and operating costs and between individual transformer loads and system loads. For this reason, DOE estimated hourly loads on individual liquid-immersed transformers using a statistical model that simulates two relationships: (1) The relationship between system load and system marginal price; and (2) the relationship between the transformer load and system load. Both are estimated at a regional level.
Transformer loading is an important factor in determining which types of transformer designs will deliver a specified efficiency, and for calculating transformer losses. For the NOPR, DOE estimated a range of loading for different types of transformers based on analysis done for the 2007 final rule. During the negotiations the load distributions were presented and found to be reasonable by the parties. In addition, data submitted by Moon Lake Electric during the negotiations were used to validate the load models for single-phase liquid-immersed distribution transformers.
For the NOPR, higher-capacity three-phase liquid-immersed and medium-voltage dry-type transformers were loaded at 20 to 66 percent, and smaller capacity single-phase medium-voltage liquid-immersed transformers were loaded at 20 to 60 percent. Low-voltage dry-type transformers were loaded at 3 to 45 (mean of 25) percent.
Cooper stated that the average loading used for liquid-filled transformers was underestimated, and historical utility evaluation factors suggest 50 percent loading for single-phase liquid-immersed transformers and closer to 60 percent for three-phase liquid-immersed transformers. (Cooper, No. 165 at p. 5) EEI stated that higher capacity three-phase distribution transformers are likely to be serving large industrial facilities with higher loading factors. (EEI, No. 185 at p. 14) Utilities stakeholders responded with a wide range of average loading values that they have on their distribution transformers: ComEd stated that its aggregated load factors range from approximately 40 to 70 percent depending on the customer class. (ComEd, No. 184 at p. 2) MLGW stated that its average aggregated load factor was approximately 17 percent across its distribution system. (MLGW, No. 133 at p. 1) PEPCO agreed that the average aggregate load factors presented in the NOPR were a good compromise and that they should not be changed. (PEMCO, No.183 at p. 2)
As previously mentioned, DOE was able to validate its load models for single-phase liquid-immersed transformers using submitted data, so it retained the loading used in the NOPR for the final rule. For three-phase liquid-immersed transformers, DOE believes that the comment from Cooper does not provide an adequate basis for changing the loading range that was viewed as reasonable by the parties to the negotiation and the loading values provided by utilities comport with DOE's estimated loadings.
Dry-type distribution transformers are primarily installed on buildings and owned by the building owner/operator. Commercial and industrial (C&I) utility customers are typically billed monthly, with the bill based on both electricity consumption and demand. Hence, the value of improved transformer efficiency depends on both the load impacts on the customer's electricity consumption and demand and the customer's marginal prices.
The customer sample of dry-type distribution transformer owners was taken from the EIA Commercial Buildings Energy Consumption Survey (CBECS) databases.
DOE conducts LCC and PBP analyses to evaluate the economic impacts on individual customers of potential energy conservation standards for distribution transformers.
For any given efficiency level, DOE measures the PBP and the change in LCC relative to an estimate of the base-case efficiency levels. The base-case estimate reflects the market in the absence of amended energy conservation standards, including the market for equipment that exceeds the current energy conservation standards.
Equipment price, installation cost, and baseline and standard affect the installed cost of the equipment. Transformer loading, load growth, power factor, annual energy use and demand, electricity costs, electricity price trends, and maintenance costs affect the operating cost. The compliance date of the standard, the discount rate, and the lifetime of equipment affect the calculation of the present value of annual operating cost savings from a proposed standard. Table IV.16 below summarizes the major inputs to the LCC and PBP analysis, and whether those inputs were revised for the final rule.
DOE calculated the LCC and PBP for a representative sample (a distribution) of individual transformers. In this manner, DOE's analysis explicitly recognized that there is both variability and uncertainty in its inputs. DOE used Monte Carlo simulations to model the distributions of inputs. The Monte Carlo process statistically captures input variability and distribution without testing all possible input combinations. Therefore, while some atypical situations may not be captured in the analysis, DOE believes the analysis captures an adequate range of situations in which transformers operate.
The following sections contain brief discussions of comments on the inputs and key assumptions of DOE's LCC and PBP analysis and explain how DOE took these comments into consideration.
The LCC spreadsheet uses a purchase-decision model that specifies which of the hundreds of designs in the engineering database are likely to be selected by transformer purchasers to meet a given efficiency level. The engineering analysis yielded a cost-efficiency relationship in the form of manufacturer selling prices, no-load losses, and load losses for a wide range of realistic transformer designs. This set of data provides the LCC model with a distribution of transformer design choices.
DOE used an approach that focuses on the selection criteria customers are known to use when purchasing transformers. Those criteria include first costs, as well as what is known in the transformer industry as total owning cost (TOC). The TOC method combines first costs with the cost of losses. Purchasers of distribution transformers, especially in the utility sector, have long used the TOC method to determine which transformers to purchase.
The utility industry developed TOC evaluation as an easy-to-use tool to reflect the unique financial environment faced by each transformer purchaser. To express variation in such factors as the cost of electric energy, and capacity and financing costs, the utility industry developed a range of evaluation factors, called A and B values, to use in their calculations. A and B are the equivalent first costs of the no-load and load losses (in $/watt), respectively.
DOE used evaluation rates as follows: 10 percent of liquid-immersed transformers were evaluated, 2 percent of low-voltage dry-type transformers were evaluated, and 2 percent of medium-voltage dry-type transformers were evaluated. The transformer selection approach is discussed in detail in chapter 8 of the final rule TSD.
In the LCC and PBP analysis, the equipment costs faced by distribution transformer purchasers are derived from the MSPs estimated in the engineering analysis and the overall markups estimated in the markups analysis.
To forecast a price trend for the NOPR, DOE derived an inflation-adjusted index of the PPI for electric power and specialty transformer manufacturing from 1967 to 2010. These data show a long-term decline from 1975 to 2003, and then a steep increase since then. DOE believes that there is considerable uncertainty as to whether the recent trend has peaked, and would be followed by a return to the previous long-term declining trend, or whether the recent trend represents the beginning of a long-term rising trend due to global demand for distribution transformers and rising commodity costs for key transformer components. Given the uncertainty, DOE chose to use constant prices (2010 levels) for both its LCC and PBP analysis and the NIA. For the NIA, DOE also analyzed the sensitivity of results to alternative transformer price forecasts.
DOE did not receive comments on the most appropriate trend to use for real transformer prices, and it retained the approach used for the NOPR for today's final rule.
Higher efficiency distribution transformers tend to be larger and heavier than less efficient designs. The degree of weight increase depends on how the design is modified to improve efficiency. In the NOPR analysis, DOE estimated the increased cost of installing larger, heavier transformers based on estimates of labor cost by transformer capacity from Electrical Cost Data 2011 Book by RSMeans.
For pole-mounted transformers, represented by design lines (DL) 2 and 3, the increased weight may lead to situations where the pole needs to be replaced to support the additional weight of the transformer. This in turn leads to an increase in the installation cost. To account for this effect in the analysis, three steps are needed:
The first step is to determine whether the pole needs to be changed. This depends on the weight of the existing transformer compared to the weight of the transformer under a proposed efficiency level, and on assumptions about the load-bearing capacity of the pole. In the NOPR analysis, it was assumed that a pole change-out will only be necessary if the weight increase is larger than 15 percent of the weight of the baseline unit, which DOE used to represent the existing transformer, and more than 150 pounds heavier for a design line 2 transformer, and 1,418 pounds heavier for a design line 3 transformer. While EEI stated that it may take less than a 1,418 pound increase for a design line 3 distribution transformer to require a pole change out (EEI, No. 229 at p. 2), neither EEI nor its members provided comments to support a different value. Therefore, DOE believes there is not a compelling reason to change from the approach used in the NOPR. Utility poles are primarily made of wood. Both ANSI
HI commented that there very likely will be a sizeable number of situations where a new pole may be required, but it noted that DOE's assumption that up to 25 percent of the total pole-mounted transformer population may require pole replacements is probably a reasonable figure. (HI, No. 151 at p. 8) EEI, APPA and NRECA suggested that the pole change-out fraction be increased to as high as 50 percent to 75 percent of units located in cities with populations of at least 25,000. (EEI, No. 185 at p. 14; NRECA, No. 172 at p. 10; APPA, No. 191 at p. 12) EEI, NRECA, and APPA did not provide evidence or rationale to support their suggestion of a higher change-out fraction for urban utilities in their comments. Therefore, DOE believes there is not a compelling reason to change from the approach used in the NOPR.
The second step is to determine the cost of a pole change-out. In the NOPR phase, specific examples of pole change-out costs were submitted by the sub-committee. These examples were consistent with data taken from the
Utility poles have a finite lifetime so, in some cases, pole change-out due to increased transformer weight should be counted as an early replacement of the pole; i.e., it is not correct to attribute the full cost of pole replacement to the transformer purchase. Equivalently, if a pole is changed out when a transformer is replaced, it will have a longer lifetime relative to the pole it replaces, which offsets some of the cost of the pole installation. To account for this effect, pole installation costs are multiplied by a factor
DOE received a number of comments on pole replacement costs. Westar stated that it costs them approximately $2,330 to replace an existing pole with a 50-foot Class 1 pole for a 100 kVA distribution transformer, which might be the new norm for residential areas. It added that whenever they replace a pole they would lose NESC grandfathering for that structure and have to redo everything on the pole to bring it up to the current NESC code, instead of merely switching out the transformer. This results in additional labor. (Westar, No. 169 at p. 2) BG&E commented that DOE's methodology may not reflect the true costs of pole change-outs, as pole replacement costs quoted by industry experts are either estimates or they reflect actual costs from previous years. In BG&E's experience, actual costs tend to exceed the estimates by a significant amount (20 to 60 percent). In 2011, its average pole replacement cost was $7,100, which includes the cost of the new pole along with any replacement material used during the installation. (BG&E, No. 223 at p. 2) ComEd also stated that DOE may have underestimated the cost of pole change-outs. At ComEd, the average pole replacement cost is in the range of $4,000–$5,000, which includes the cost of the new pole along with any replacement material and labor. (ComEd, No. 184 at p. 13) Progress Energy stated that it realized average pole replacement costs of $2,200 during 2011, but it noted that during the negotiated meetings, utilities reported pole replacement costs upwards of $12,000. Progress Energy recommended that DOE continue to use the pole replacement costs that they have been using so that the final rule will not be delayed. (Progress Energy, No. 192 at p. 9) EEI suggested that DOE increase the pole change-out cost estimates to a range of values (or a weighted average) provided by EEI member companies. (EEI, No. 185 at p. 14)
The information that DOE received regarding average pole replacement costs was of limited use because most of the utilities did not provide their average pole replacement costs for the transformer capacities used in the analysis. However, DOE notes that the pole replacement costs mentioned in the above comments fall within the range of costs that DOE used for its pole-mounted design lines (design lines 2 and 3). DOE recognizes that there may be some cases where the pole replacement cost may be outside this range, but these would account for a very small fraction of situations.
Westar stated that when mounting a bank of three‐phase transformers on a pole, if the weight increased beyond 2,000 pounds per position (which wouldn't be out of the realm of possibility for a transformer using amorphous core steel), they would need to use a 500kVA pad mount. (Westar, No. 169 at p. 2) DOE recognizes that in some situations pole replacement may not be an acceptable option to utilities when replacing transformers. DOE believes that the range of installation costs that it used for pole replacement, in combination with the weight-based installation costs, captures the cost of situations where a pad mount would be needed.
Westar commented that a new design for a pad-mounted transformer could require larger fiberglass pads than they currently use, or they would have to start pouring a concrete pad for each pad mount. (Westar, No. 169 at p. 3) DOE believes that the installation costs it used for pad-mounted transformers, which range from $2,169 for design line 1 (at 50 kVA) to $8,554 for design line 5 (at 1500 kVA), encompass the situation described by Westar.
DOE's assumptions about loading of different types of transformers are described in section IV.E. DOE generally estimated that the loading of larger capacity distribution transformers is greater than the loading on smaller capacity transformers.
The LCC analysis takes into account the projected operating costs for distribution transformers many years into the future. This projection requires an estimate of how the electrical load on transformers will change over time. In the NOPR analysis, for dry-type transformers, DOE assumed no-load growth, while for liquid-immersed transformers DOE used as the default scenario a one-percent-per-year load growth. It applied the load-growth factor to each transformer beginning in 2016. To explore the LCC sensitivity to variations in load growth, DOE included in the model the ability to examine scenarios with zero percent, one percent, and two percent load growth.
DOE did not receive comments regarding its load-growth assumptions, and it retained the assumptions described above for the final rule analysis.
DOE used estimates of electricity prices and costs to place a value on transformer losses. For the NOPR, DOE performed two types of analyses. One investigated the nature of hourly transformer loads, their correlation with the overall utility system load, and their correlation with hourly electricity costs and prices. Another estimated the impacts of transformer loads and resultant losses on monthly electricity usage, demand, and electricity bills. DOE used the hourly analysis for liquid-immersed transformers, which are owned predominantly by utilities that pay costs that vary by the hour. DOE used the monthly analysis for dry-type transformers, which typically are owned by commercial and industrial establishments that receive monthly electricity bills.
For the hourly price analysis, DOE used marginal costs of electricity, which are the costs to utilities for the last kilowatt-hour of electricity produced. The general structure of the hourly marginal cost equation divides the costs
Commenting on DOE's hourly price analysis, NRECA stated that marginal energy prices recover the system generation capacity costs, and demand charges are not needed to collect capacity charges. (NRECA, No. 156 at pp. 4–5) It added that use of demand charges introduces bias towards improved cost-effectiveness of more efficient transformers. (NRECA, No. 156 at p. 7)
DOE disagrees with NRECA's position that demand charges are not needed to collect capacity charges. DOE agrees that marginal energy prices in a single price-clearing auction can provide for recovery of some amount of generation capacity cost, but it is unlikely that an energy-only market (one that relies only on market incentives for investment) would provide for full recovery of system generation capacity costs.
Whether an area has a capacity market or capacity requirements, a reduction in electricity demand due to more efficient transformers would lower the amount of capacity purchases required by LSEs, which would lower capacity procurement costs. DOE's application of demand charges captures these lower procurement costs.
DOE acknowledges that not all electricity markets have structured capacity markets or capacity requirements. The Electric Reliability Council of Texas (ERCOT), an energy-only market without set requirements for generation capacity procurement, is premised on the energy market and the ancillary service markets being able to provide sufficient revenues to attract new market entrants as needed. The expectation is that as reserve margins decline, market prices would increase to provide the needed revenues for new investment. In the long-term, absent the cessation of demand growth, one would expect market revenues to equal the full cost of a new market entrant.
Many publicly owned utilities (POU) are not required to participate in capacity markets or mandated to attain specified amounts of generation capacity. Capacity attainment is at the sole discretion of those POU's governing bodies, but DOE expects that POUs would continue to build or contract with sufficient capacity to provide reliable service to their customers. As this capacity procurement will impose a cost that is incremental to the utility's system marginal energy cost, the use of capacity costs is also appropriate for evaluation of transformer economics for these utilities.
Although DOE believes it is appropriate to include demand charges, for the final rule, DOE reviewed its capacity cost methodology and found that the demand charges used in the NOPR analysis were too high. In the NOPR, demand charges were based on the full fixed cost of new generation. For the final rule, the revised demand charges are based on the full cost of new generation net of the revenues that the generator could earn from the hourly energy market. This quantification of capacity costs net of market revenues is consistent with the design of the nation's capacity markets, including PJM RPM Capacity Market
In the NOPR, to value the capacity costs, DOE used advanced coal technology to reflect generation capacity
For the relative change in electricity prices in future years, DOE relied on price forecasts from the Energy Information Administration (EIA)
In the NOPR, to project the relative change in electricity prices for liquid-immersed transformers, DOE used the average electricity prices from AEO 2011. NRECA stated that gas-fired combustion turbines and combined cycle units are being used to service base loads today, as well as meeting peak demand (NRECA, No. 156 at p. 9), and EEI asserted that natural gas is the marginal fuel “a lot” of the time (EEI, No. 0051–0030 at p. 108). DOE agrees with both of these statements. For the final rule, DOE assumed that future production cost of electricity for utilities, the primary owners of liquid-immersed transformers, would be influenced by the price of fuel for generation (i.e., coal and natural gas). To estimate the relative change in the price to produce electricity in future years in today's rule, DOE applied separate price trends to both no-load and load losses. DOE used the sales weighted price trend of both natural gas and coal to estimate the relative price change for no-load losses; and natural gas only to estimate the relative price change for load losses. These trends are based on the AEO 2012 projections and are described in greater detail in chapter 8 of the TSD.
Appendix 8–D of this final rule TSD provides a sensitivity analysis for equipment of a sub-set of representative design lines. These analysis shows that the effect of changes in electricity price trends, compared to changes in other analysis inputs, is relatively small.
DOE calculated customer impacts as if each new distribution transformer purchase occurs in the year that manufacturers must comply with the standard. As discussed in section II.A, if DOE finds that amended standards for distribution transformers are warranted, DOE agreed to publish a final rule containing such amended standards by October 1, 2012. The compliance date of January 1, 2016, provides manufacturers with over three years to prepare for the amended standards.
The discount rate is the rate at which future expenditures are discounted to estimate their present value. DOE employs a two-step approach in calculating discount rates for analyzing customer economic impacts. The first step is to assume that the actual customer cost of capital approximates the appropriate customer discount rate. The second step is to use the capital asset pricing model (CAPM) to calculate the equity capital component of the customer discount rate. For the preliminary analysis, DOE estimated a statistical distribution of commercial customer discount rates that varied by transformer type by calculating the cost of capital for the different types of transformer owners.
More detail regarding DOE's estimates of commercial customer discount rates is provided in chapter 8 of the final rule TSD.
DOE defined distribution transformer life as the age at which the transformer retires from service. For the NOPR analysis, DOE estimated, based on a report by Oak Ridge National Laboratory,
To determine an appropriate base case against which to compare various potential standard levels, DOE used the purchase-decision model described in section IV.F.1. For the base case, initially transformer purchasers are allowed to choose among the entire range of transformers at each design line. Transformers are chosen based on either lowest first cost, or if the purchaser is an evaluator, on lowest Total Owning Cost (TOC). During the negotiations (see section II.B.2) manufacturers and utilities stated that ZDMH is not currently used in North America, so designs using ZDMH as a core steel were excluded from the base case.
The payback period is the amount of time it takes the consumer to recover the additional installed cost of more efficient products, compared to baseline products, through energy cost savings. Payback periods are expressed in years. Payback periods that exceed the life of the product mean that the increased total installed cost is not recovered in reduced operating expenses.
The inputs to the PBP calculation are the total installed cost of the product to the customer for each efficiency level and the average annual operating expenditures for each efficiency level. The PBP calculation uses the same inputs as the LCC analysis, except that discount rates are not needed.
As noted above, EPCA, as amended, establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy (and, as applicable, water) savings during the first year that the consumer will receive as a result of the standard, as calculated under the test procedure in place for that standard. (42 U.S.C. 6295(o)(2)(B)(iii)) For each considered efficiency level, DOE determines the value of the first year's energy savings by calculating the quantity of those savings in accordance with the applicable DOE test procedure, and multiplying that amount by the average energy price forecast for the year in which compliance with the amended standards would be required.
DOE's NIA assessed the national energy savings (NES) and the national NPV of total customer costs and savings that would be expected to result from amended standards at specific efficiency
To make the analysis more accessible and transparent to all interested parties, DOE used an MS Excel spreadsheet model to calculate the energy savings and the national customer costs and savings from each TSL.
DOE evaluated the impacts of amended standards for distribution transformers by comparing base-case projections with standards-case projections. The base-case projections characterize energy use and customer costs for each equipment class in the absence of amended energy conservation standards. DOE compared these projections with projections characterizing the market for each equipment class if DOE were to adopt amended standards at specific energy efficiency levels (i.e., the standards cases) for that class.
Table IV.27 and Table IV.38 summarize all the major NOPR inputs to the shipments analysis and the NIA, and whether those inputs were revised for the final rule.
DOE projected transformer shipments for the base case by assuming that long-term growth in transformer shipments will be driven by long-term growth in electricity consumption. The detailed dynamics of transformer shipments is highly complex. This complexity can be seen in the fluctuations in the total quantity of transformers manufactured as expressed by the U.S. Department of Commerce, Bureau of Economic Analysis (BEA), transformer quantity index. DOE examined the possibility of modeling the fluctuations in transformers shipped using a bottom-up model where the shipments are triggered by retirements and new capacity additions, but found that there were not sufficient data to calibrate model parameters within an acceptable margin of error. Hence, DOE developed the transformer shipments projection by assuming that annual transformer shipments growth is equal to growth in electricity consumption as given by the
DOE recognizes that increase in transformer prices due to standards may cause changes in purchase of new transformers. Although the general trend of utility transformer purchases is determined by increases in generation, utilities conceivably exercise some discretion in how much transformer capacity to buy—the amount of “over-capacity” to purchase. In addition, some utilities may choose to refurbish transformers rather than purchase a new transformer if the price of the latter increases significantly.
To capture the customer response to transformer price increase, DOE estimated the customer price elasticity of demand. In DOE's estimation of the purchase price elasticity, it used a logit function to characterize the utilities' response to the price of a unit capacity of transformer. The functional form captures what can be called an average price elasticity of demand with a term to capture the estimation error, which accounts for all other effects. Although DOE was not able to explicitly model the replace versus refurbish decision due to lack of necessary data, the price elasticity should account for any decrease in the shipments due to a decision on the customer's part to refurbish transformers as opposed to purchasing a new unit. DOE's approach is described in chapter 9 of the final rule TSD. Comments on the issue of replacing versus refurbishing are discussed in section IV.O.3 of this preamble.
DOE did not include any base case efficiency trend in its shipments and national energy savings models. AEO forecasts show no long term trend in transmission and distribution losses, which are indicative of transformer efficiency. DOE estimates that the probability of an increasing efficiency trend and the probability of a decreasing efficiency trend are approximately equal, and therefore assumed no trend in base case or standards case efficiency.
For each year in the forecast period, DOE calculates the national energy savings for each standard level by multiplying the stock of products affected by the energy conservation standards by the per-unit annual energy savings. Cumulative energy savings are the sum of the NES for each year.
To estimate national energy savings, DOE uses a multiplicative factor to convert site energy consumption into primary energy consumption (the energy required to convert and deliver the site energy). This conversion factor accounts for the energy used at power plants to generate electricity and losses in transmission and distribution. The conversion factor varies over time because of projected changes in the power plant types projected to provide electricity to the country. The factors that DOE developed are marginal values, which represent the response of the system to an incremental decrease in consumption associated with standards. For today's rule, DOE used annual conversion factors based on the version of NEMS that corresponds to
Section 1802 of EPACT 2005 directed DOE to contract a study with the National Academy of Science (NAS) to examine whether the goals of energy efficiency standards are best served by measuring energy consumed, and efficiency improvements, at the actual point of use or through the use of the full-fuel-cycle, beginning at the source of energy production. (Pub. L. 109–58 (August 8, 2005)). NAS appointed a committee on “Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy Efficiency Standards” to conduct the study, which was completed in May 2009. The NAS committee defined full-fuel-cycle energy consumption as including, in addition to site energy use: Energy consumed in the extraction, processing, and transport of primary fuels such as coal, oil, and natural gas; energy losses in thermal combustion in power generation plants; and energy losses in transmission and distribution to homes and commercial buildings.
In evaluating the merits of using point-of-use and full-fuel-cycle (FFC) measures, the NAS committee noted that DOE uses what the committee referred to as “extended site” energy consumption to assess the impact of energy use on the economy, energy security, and environmental quality. The extended site measure of energy consumption includes the energy consumed during the generation, transmission, and distribution of electricity but, unlike the full-fuel-cycle measure, does not include the energy consumed in extracting, processing, and transporting primary fuels. A majority of the NAS committee concluded that extended site energy consumption understates the total energy consumed to make an appliance operational at the site. As a result, the NAS committee recommended that DOE consider shifting its analytical approach over time to use a full-fuel-cycle measure of energy consumption when assessing national and environmental impacts, especially with respect to the calculation of greenhouse gas (GHG) emissions. For those appliances that use multiple fuels, the NAS committee indicated that measuring full-fuel-cycle energy consumption would provide a more complete picture of energy consumed and permit comparisons across many different appliances, as well as an improved assessment of impacts.
In response to the NAS committee recommendations, on August 18, 2011, DOE announced its intention to use full-fuel-cycle measures of energy use and greenhouse gas and other emissions in the national impact analyses and emissions analyses included in future energy conservation standards rulemakings. 76 FR 51282 While DOE stated in that notice that it intended to use the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model to conduct the analysis, it also said it would review alternative methods,
As noted in section IV.F.2, DOE assumed no change in transformer prices over the 2016–2045 period. In addition, DOE conducted sensitivity analysis using alternative price trends. Based on PPI data for electric power and specialty transformer manufacturing, DOE developed one forecast in which prices decline after 2010, and one in which prices rise. These price trends, and the NPV results from the associated sensitivity cases, are described in appendix 10–C of the final rule TSD.
The inputs for determining the net present value (NPV) of the total costs and benefits experienced by consumers of considered appliances are: (1) Total annual installed cost; (2) total annual savings in operating costs; and (3) a discount factor. DOE calculates net savings each year as the difference between the base case and each standards case in total savings in operating costs and total increases in installed costs. DOE calculates operating cost savings over the life of each product shipped during the forecast period.
In calculating the NPV, DOE multiplies the net savings in future years by a discount factor to determine their present value. DOE estimates the NPV using both a 3-percent and a 7-percent real discount rate, in accordance with guidance provided by the Office of Management and Budget (OMB) to Federal agencies on the development of regulatory analysis.
In analyzing the potential impacts of new or amended standards, DOE evaluates impacts on identifiable groups (i.e., subgroups) of customers that may be disproportionately affected by a national standard.
A number of parties expressed specific concerns about size and space constraints for network/vault transformers. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11; Pepco, No. 145 at pp. 2–3; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12)
For today's final rule, DOE evaluated purchasers of vault-installed transformers (mainly utilities concentrated in urban areas), represented by design lines 4 and 5, as a customer subgroup, and examined the impact of standards on these groups using the methodology of the LCC and PBP analysis. DOE examined the impacts of larger transformer volume with regard to costs for vault enlargement. DOE assumed that if the volume of a unit in a standard case is larger than the median volume of transformer designs for the particular design line, a vault modification would be warranted. To estimate the cost, DOE compared the difference in volume between the unit selected in the base case against the unit selected in the standard case, and applied fixed and variable costs. In the 2007 final rule, DOE estimated the fixed cost as $1,740 per transformer and the variable cost as $26 per transformer cubic foot.
The customer subgroup analysis is discussed in detail in chapter 11 of the final rule TSD.
DOE performed a manufacturer impact analysis (MIA) to estimate the financial impact of amended energy conservation standards on manufacturers of distribution transformers and to calculate the impact of such standards on employment and manufacturing capacity. The MIA has both quantitative and qualitative aspects. The quantitative part of the MIA primarily relies on the Government Regulatory Impact Model (GRIM), an industry cash-flow model with inputs specific to this rulemaking. The key GRIM inputs are data on the industry cost structure, product costs, shipments, and assumptions about markups and conversion expenditures. The key output is the INPV. Different sets of shipment and markup assumptions (scenarios) will produce different results. The qualitative part of the MIA addresses factors such as product characteristics, impacts on particular sub-groups of firms, and important market and product trends. The complete MIA is outlined in chapter 12 of the TSD.
New and amended energy conservation standards will cause manufacturers to incur conversion costs to bring their production facilities and product designs into compliance. For the MIA, DOE classified these conversion costs into two major groups: (1) Product conversion costs and (2) capital conversion costs. DOE's estimates of the product and capital conversion costs for distribution transformers can be found in section V.B.2.a of today's final rule and in chapter 12 of the TSD.
Product conversion costs are investments in research, development, testing, marketing, and other non-capitalized costs necessary to make product designs comply with the new or amended energy conservation standard. DOE based its estimates of the product conversion costs that would be required to meet each TSL on information obtained from manufacturer interviews, the engineering analysis, and the NIA shipments analysis. For the distribution transformer industry, a large portion of product conversion costs will be related to the production of amorphous cores, which would require the development of new designs, materials management, and safety measures. Procurement of such technical expertise may be particularly difficult for manufacturers
Capital conversion costs are investments in property, plant, and equipment necessary to adapt or change existing production facilities such that new equipment designs can be fabricated and assembled. For capital conversion costs, DOE prepared bottom-up estimates of the costs required to meet standards at each TSL for each design line. To do this, DOE used equipment cost estimates provided by manufacturers and equipment suppliers, an understanding of typical manufacturing processes developed during interviews and in consultation with subject matter experts, and the properties associated with different core and winding materials. Major drivers of capital conversion costs include changes in core steel type (and thickness), core weight, core stack height, and core construction techniques, all of which are interdependent and can vary by efficiency level. DOE uses estimates of the core steel quantities needed for each steel type, as well as the most likely core construction techniques, to model the additional equipment the industry would need to meet the efficiencies embodied by each TSL.
In the NOPR MIA, DOE modeled two standards-case markup scenarios to represent the uncertainty regarding the potential impacts on prices and profitability for manufacturers following the implementation of amended energy conservation standards: (1) A preservation of gross margin percentage markup scenario, and (2) a preservation of operating profit markup scenario. These scenarios lead to different markups values, which, when applied to the inputted MPCs, result in varying revenue and cash flow impacts. While DOE has modified several inputs to the GRIM for today's final rule, it continues to analyze these two markup scenarios for the final rule. For a complete discussion, see the NOPR or chapter 12 of the TSD.
Key inputs to the GRIM characterize the distribution transformer industry cost structure, investments, shipments, and markups. For today's final rule, DOE made several updates to the GRIM to reflect changes in these inputs since publication of the NOPR. Specifically, DOE incorporated changes made in the engineering analysis and NIA, including updates to the MPCs, shipment forecasts, and shipment efficiency distributions. In addition, DOE made minor changes to its conversion cost methodology in response to comments as described below. These updated inputs affected the values calculated for the conversion costs and markups described above, as well as the INPV results presented in section V.B.2.
The following section discusses a number of comments DOE received on the February 2012 NOPR MIA methodology. DOE has grouped the comments into the following topics: Core steel, small manufacturers, conversion costs, and benefits versus burdens.
The issue of core steel is critical to this rulemaking. This section discusses comments related to steel price projections, steel mix and competition between suppliers, and steel supply and production capacity. Most of these issues are highly interconnected.
Steel Prices. Several stakeholders commented on the steel prices used by DOE. Prolec-GE believes that the steel supply assessment in appendix 3A of the TSD was too optimistic about supply and price in a post-recession global environment and that any analysis for higher than current level efficiencies should evaluate a much higher range of material price variance that what DOE used in the NOPR. (Prolec-GE, No. 52 at p. 13) APPA notes that the analysis in appendix 3A of the TSD provides good information about prices from 2006 to 2010, but it does not include information about the significant increase in prices compared to 2002–2003 levels.
Northeast Energy Efficiency Partnerships argued that, when faced with competition, conventional high-grade electrical steel prices could come down and compete effectively with the more efficient amorphous materials. (NEEP, No. 193 at p. 3) Earthjustice expressed similar sentiments, stating that the analysis conducted by DOE on DL1 presents an unrealistic picture of the LCC impacts of meeting TSLs 2 and 3 with conventional steels in that design line because competitive pressure from amorphous metal will likely reduce the price for grain-oriented electrical steels and, therefore, improve the LCC savings for consumers. (Earthjustice, No. 195 at p. 1–3)
DOE recognizes that steel prices have proven highly volatile in the past and could continue to fluctuate in the future for a variety of reasons, including macroeconomic factors, competition among steel suppliers, trade policy and raw material prices. With respect to Earthjustice's comment, while DOE agrees that the LCC is highly sensitive to relative steel price assumptions at certain TSLs, DOE notes that a decline in silicon transformer prices would be unlikely to materially change the slope of the silicon steel transformer cost curve. Therefore, the incremental costs (and LCC savings) would not change significantly. To NEEP's comment, DOE agrees that competition between silicon steel suppliers, the incumbent amorphous metal suppliers and new market entrants will impact future prices. However, DOE does not believe it is possible to predict the relative movements in these prices. Throughout the negotiation process, stakeholders have argued for different price points for different steels under different scenarios. The eventual relative prices of steels in the out years will be in part subject to the aforementioned market forces, the direction and magnitude of which cannot be known at this time. For these reasons, DOE performed a sensitivity analysis that included a wide range of potential core steel prices to evaluate their impact on LCC savings as discussed in section V.B.3.
Diversity of Steel Mix and Competition. Most stakeholders stated a preference for a market in which traditional and amorphous steel could effectively compete, but there was disagreement over which efficiency level would strike that balance, particularly for liquid-immersed distribution transformers. The various steel types that are available on the market for distribution transformers are listed in Table 5.10 in chapter 5 of the TSD. Stakeholders generally sought a standard that would allow manufacturers to use a diversity of electrical steels that are cost-competitive and economically feasible. This issue is critical to stakeholders for several reasons, including what some worried would be a lack of amorphous steel supply, a transition to a market that currently has only one global supplier with significant capacity, as well as forced conversion costs associated with the manufacturing of amorphous steel cores.
Both APPA and Adams Electric Cooperative (AEC) commented that it is important that DOE preserve the competitive market by allowing both grain-oriented steel and amorphous core transformers to be price competitive. APPA and AEC are concerned about the availability and price of the core materials if only one product is competitively viable because this will affect jobs for traditional steel
Some stakeholders, in particular ACEEE, ASAP, NRDC, and Northwest Power and Conservation Council (NPCC), asserted that competition can still be maintained at efficiency levels higher than those proposed in the NOPR. These stakeholders believe that TSL 1 favors silicon steel and will, therefore, raise the price for silicon steel while relegating amorphous steel to niche status, relative to a higher TSL. They noted that industry sources and press accounts confirm that electrical steel is a very high profit margin product and the lack of strong competition for M3 in the current market appears to be contributing to very high M3 prices. (Advocates, No. 186 at p. 10) Therefore, the Advocates argued that a modified TSL 4 (EL2 for all design lines) for liquid-immersed transformers could be met using either amorphous metal or silicon steel, thereby increasing competition. ASAP had suggested during the NOPR public meeting that moving into a market where there would be three domestically based competitors would be a better competitive outcome than the status quo of two competitors who have the lion's share of the market. (ASAP, No. 146 at p. 38) In response to the supplementary analysis of June 20, 2012, the Advocates suggested the adoption of TSL C, which they believed would provide for robust competition among core material suppliers. (Advocates, No. 235 at p. 1) They also noted that TSL D, which consists of EL 2 for pad-mounted transformers and EL 1 for pole-mounted transformers, would favor the continued use of grain oriented electrical steel for the majority of the market and allow silicon steel and amorphous metal to reach rough cost parity for pad-mounted transformers. (Advocates, No. 235 at p. 4) ACEEE, ASAP, NRDC, and NPCC further cited some transformer manufacturers as saying TSL 4 or 3.5 (EL 2 or EL 1.5) for liquid-immersed transformers would lead to robust competition because a market currently served by two steel suppliers (AK Steel and ATI Allegheny Ludlum) would then be served by three since the amorphous metal supplier (Metglas) could compete. (Advocates, No. 186 at p. 10–11) Additional amorphous metal suppliers may also enter the market because barriers to entry into amorphous metal transformer production are, according to Metglas, quite limited. (Metglas, No. 102 at p. 2) Also, based on the results of an analysis conducted by an industry expert for ASAP, the Advocates believe that it would be very unlikely that TSL 4 standards from the NOPR for liquid-immersed transformers would result in amorphous metal market share exceeding 20 percent in the near- and medium-term due to the current dominant position of silicon steel, inertia in utility decision making, and the ability of steel makers to lower prices to protect against market share erosion. Furthermore, increases in the standards for LVDT and MVDT transformers, which have markets where amorphous metal does not compete and is not expected to compete at the levels proposed by DOE, will increase silicon steel tonnage. In the longer term, silicon steel manufacturers can make strategic investment decisions that will enable them to compete, such as increasing production of High B steel or entering amorphous metal production. (Advocates, No. 186 at pp. 12–13) Berman Economics also argued that competition between traditional and amorphous steel is still possible with higher standards for liquid-immersed transformers because, according to shipments data from ABB, TSL 4 has the greatest diversity of core materials. (Berman Economics, No. 221 at p. 7)
On the other hand, many stakeholders believe that competition among steel suppliers will not be possible at levels higher than those proposed in the NOPR. At the NOPR public meeting, ATI stated that the proposed standards maintain a competitive balance between alternative materials and grain-oriented electrical steel, which has adequate supply from annual global production levels exceeding two million metric tons and price competition from several producers. (ATI, No. 146 at p. 18) ATI believes that higher standards will result in cost-effective design options limited to amorphous metal cores for liquid-immersed transformers. Such a situation would cost U.S. jobs, increase the risk of supply shortages and disruptions, and create a non-competitive market for new liquid-immersed designs which ATI expects will eliminate any projected LCC savings. (ATI, No. 54 at p. 2) Furthermore, ATI stated that even TSL 1 may have adverse impacts on competition because the efficiency levels assigned to design lines 2 and 5 in TSL 1 were set well above the crossover point for competition between multiple core materials and therefore the implementation of TSL 1 would curtail the availability of multiple options for core material choices for liquid-immersed transformers. ATI did not support any of the new TSLs proposed in DOE's supplementary analysis, which were higher than TSL 1 and which would, according to ATI, have significant impacts on the competitiveness of grain-oriented electrical steel and result in nearly complete conversion of the liquid-immersed market to amorphous cores. (ATI Allegheny, No. 218 at p. 1) Instead, ATI proposed an alternative TSL which consists of what it believes are more accurate crossover points for the liquid-immersed design lines: EL 1.3 for DL 1, EL 0 for DL2, EL 0.7 for DL 3, EL 1 for DL 4, and EL 0.7 for DL 5. (ATI Allegheny, No. 218 at p. 1)
Cooper Power stated that the currently proposed efficiency levels are at the maximum levels that allow use of both silicon and amorphous core steels. Higher efficiency levels will tip the market in favor of amorphous materials that are not available in the quantities needed and do not have the desired diversity of suppliers to maintain a healthy market. (Cooper Power, No. 165 at p. 4) Cooper Power had found through one of its analyses that the crossover point at which transformer price is equivalent between M3 and amorphous was at EL 0.5 for all design lines 1, 3, 4, and 5 and EL 0.25 for DL2. According to Cooper Power, the best choice for raising the efficiency levels and keeping both M3 core steel and amorphous core steel competitive with one another would be to choose EL 0.5. (Cooper Power Systems, No. 222 at p. 2) During the NOPR public meeting, Cooper Power commented that, past EL 1, it is no longer a level playing field between amorphous and silicon core steel. (Cooper Power, No. 146, at p. 49–50) HVOLT also commented that the crossover point between M3 and amorphous is at EL 1, and it's a hard move to amorphous past that level. (HVOLT, No. 146 at p. 51) The United Auto Workers (UAW) is concerned that requiring efficiency levels beyond TSL–1 for liquid-immersed transformers would impose unwarranted conversion costs on transformer producers, force the use of amorphous metals that are not available in adequate supply, and create significant anticompetitive market power for the producer of amorphous metal electrical steel. (UAW, No. 194 at
DOE recognizes the importance of maintaining a competitive market for transformer steel supply in which traditional steel and amorphous steel suppliers can both participate. This was a critical consideration in DOE's assessment of the rule's impact on competition. As with the discussion on future prices, the precise “crossover point” is variable depending on a number of factors, including firm pricing strategies, global demand and supply, trade policy, market entry, and economies of scale among producers and consumers of the core steel. The magnitudes of these potential influences on the cross-over point cannot be precisely known in advance.
DOE attempted to survey manufacturers about the mix of core steel used currently for transformers meeting various efficiency levels and also queried the industry about their expectations for core steel mix at those efficiencies should the next DOE standard require them. However, beyond those presentations made publicly by various manufacturers during the negotiations—which demonstrated conflicting views on the “crossover point”—DOE could not gather sufficient data to calculate manufacturer expectations of the crossover point at various TSLs. While several stakeholders have pointed to the “tipping point” shown by the LCC's steel selection analysis as evidence that the market will transition to amorphous entirely for some design lines, DOE repeats here that not every possible design was analyzed and that the LCC tool is highly sensitive to price assumptions which have been shown to be extremely variable over time and among suppliers. Balancing all of the evidence in this docket, DOE believes that the levels established by today's final rule will maintain a choice of steel mix for the industry. As discussed in the weighing of benefits and burdens section (section IV.I.5.d), DOE remains concerned about the potential for significant disruption in the steel supply market at levels higher than those established by today's rule.
As for the conversion costs that may be required should some manufacturers decide to begin making, or to increase production of, amorphous core transformers, DOE accounts for them in the GRIM analysis.
Supply and Capacity. The ability of core steel producers to increase supply if necessary is another related key issue discussed by stakeholders. Some stakeholders were concerned that suppliers may not have the capacity to produce certain steels in quantities great enough to meet demand at higher efficiency levels, while other stakeholders believed that suppliers will be fully capable of expanding capacity as needed.
Several stakeholders expressed concerns about utilities being unable to serve customers due to steel supply constraints in the distribution chain. EEI stated that its members do not want to repeat the situation they faced in 2006–2008 when there were transformer shortages and utilities were told that there would be delays of months or even years before certain transformers would be available. (EEI, No. 185 at p. 10) APPA noted that the threat of transformer rationing may return in an improved economy and hamper the ability of utilities to meet their obligation to serve customers. (APPA, No. 191 at p. 10) Likewise, Consolidated Edison believes that the possible requirement to use higher grade core steels in order to achieve higher efficiencies may result in supply scarcity, increased costs, and tough competition for these materials after recovery from the global recession. (ConEd, No. 236 at p. 4) Commonwealth Edison Company is very concerned about the availability of a quality steel supply for the transformer manufacturing industry and that a limited supply of transformers will have a significant negative effect on the company's ability to provide safe and reliable electric service to its customers. (ComEd, No. 184 at p. 11) Howard Industries is also concerned about the limited availability of critical core materials such as M2 and amorphous, which could pose a large risk to the transformer and utility industries and may become a particularly troublesome issue if the economy and housing markets return to more normal levels. (Howard Industries, No. 226 at p. 2) In addition, the USW stated that the number of transformer producers with the equipment to build reliable transformers with amorphous ribbon cores is relatively small. Therefore, a sudden transition to amorphous ribbon would result in a fragile supply chain for distribution transformers, potentially leading to large cost increases and supply shortages that would place the security of the U.S. electrical transmission grid at risk. (USW, No. 148 at p. 2) ATI stated during the NOPR
Some stakeholders also emphasized the importance of being able to use M3 steel, which is more readily available than other more efficient steels. Prolec-GE noted that silicon steel grades above M3 have significant supply limitations and predicted no change in that situation for the foreseeable future. Therefore, Prolec-GE continues to see the need for a balanced approach to higher efficiencies such that M3 silicon steel and amorphous metal can compete for a share of the liquid-immersed market, which would allow manufacturers to have a sufficient supply of these materials to serve customer requirements. (Prolec-GE, No. 52 at pp. 11–12) Progress Energy also stated that M2 core steel is in short supply because it is only a small part of a silicon core steel producer's output and M3 and M4 grades of core steel should be required for 85 percent or more of any required efficiency level so that utilities will not face shortage situations that would have negative impacts on grid reliability. (Progress Energy, No. 192 at pp. 7–8) Likewise, Power Partners voiced concern about the U.S. supply of core steel should DOE adopt an efficiency that requires the use of grades better than M3. Power Partners stated that the current domestic capacity for M2 will not support 100 percent of all liquid-immersed transformers and, therefore, recommended that DOE only consider efficiency levels that can be attained with M3 core steel with no loss evaluation. The grades better than M3 should be employed when the utility loss evaluation justifies its use. (Power Partners, No. 155 at pp. 3–4) Southern California Edison has stated that greater market demand for M2 core steel may create supply shortages and result in high steel prices. (Southern California Edison, No. 239 at p. 1) According to Central Moloney, M2 and higher grades of steel are premium products within the steel manufacturing process which comprise no more than 15 percent of overall steel production. Central Moloney is concerned that the marketplace will not be able to support the demand of these premium products if efficiency levels are increased. (Central Moloney, No. 224 at pp. 1–2)
Stakeholders have also expressed several concerns regarding the availability of steels supplied by foreign vendors, especially amorphous steel. Both Commonwealth Edison Company and Baltimore Gas and Electric Company stated that the overseas procurement of steel could result in specification issues and that there could be a negative impact on the U.S. electric grid if DOE sets a standard that requires the use of a specific core steel that is not readily available in the domestic market and which does not have a proven track record. (ComEd, No. 184 at p. 12 and BG&E, No. 182 at p. 7) Power Partners has stated that grades of grain-oriented electrical steel better than M2 for wound core applications are only available from international sources and supply capacity is very limited. (Power Partners, No. 155 at pp. 3–4) In addition, Progress Energy is concerned that amorphous and mechanically scribed core steel will not be available in sufficient quantities because domestic transformer vendors rely on basically one amorphous core steel provider. This supplier may not have the capacity to provide enough amorphous material to meet demand from all U.S. transformer manufacturers as well as overseas business if the efficiency levels are increased beyond EL 1 for liquid-immersed distribution transformers. (Progress Energy, No. 192 at pp. 7–8) ABB has indicated that amorphous steel is a sole source product for the U.S., and, as demand increases for it, there could be a tight global supply as well as upward price pressure. (ABB, No. 158 at p. 8) ABB has also expressed concerns about mechanically scribed steel. This type of steel has only four global suppliers, and its availability may be subject to international trade restrictions. (ABB, No. 158 at p. 8) According to Cooper Power Systems, ZDMH is in large part unavailable in the U.S. and should therefore represent only a small fixed percentage of overall usage. (Cooper Power Systems, No. 222 at p. 2)
However, some stakeholders are more confident that the supply of higher efficiency steels would increase to meet demand due to higher standards. ACEEE, ASAP, NRDC, and NPCC believe that it is highly unlikely that amorphous production will not expand in response to higher standards because: (1) The U.S. producer of amorphous metal has demonstrated its ability to add capacity over the past several years as producers of high-value electricity (e.g., wind producers) have favored amorphous metal products, and (2) other manufacturers are exploring amorphous production and there are no legal barriers to entry for new competitors. (Advocates, No. 186 at p. 11) The Advocates also noted that one of the largest global suppliers of silicon steel for transformers, POSCO (formerly Pohang Iron and Steel Company), is entering the amorphous metal market. The company approved a plan for commercializing amorphous metal production in 2010 and will soon begin production and marketing of amorphous metal with plans to produce up to 1 kiloton (kt) in 2012, 5 kt in 2013, and 10 kt in 2014. (Advocates, No. 235 at p. 3) Schneider Electric stated that, with the exception of amorphous, there are sufficient suppliers worldwide (Europe and Asia) who have either increased capacity or who have near term plans to increase capacity to meet the growing demand for high-grade steels. The company feels it is better to allow global market conditions to dictate business plans rather than the DOE because manufacturing and freight costs play a lesser role than supply and demand in determining the final price for high-grade steels, whether domestic or foreign, as long as there are sufficient suppliers worldwide. (Schneider, No. 180 at p. 6) In addition, Hydro-Quebec has stated that the equipment for making amorphous steels is mainly used to serve the distribution transformer market, which allows amorphous steel to be less influenced by other non-transformer markets that may impact steel price and availability. Amorphous steel production lines are also much smaller than silicon steel lines, thereby allowing amorphous steel makers to add production capacity by small increments with relatively low capital expenditures and in a relatively short time frame. Hydro-Quebec therefore believes that amorphous steel production can be tightly connected with increasing demand. (Hydro-Quebec, No. 125 at p. 2) Metglas, has also stated that an increase in capacity to even 100 percent of 2016 demand would only require an approximately $200M investment in amorphous metal casting capacity and an even smaller total industry investment by core/transformer makers in amorphous metal transformer manufacturing capacity. Metglas further stated that it has a technology transfer program to assist any U.S. transformer maker in quickly progressing into production of amorphous metal-based transformers. (Metglas, No. 102 at p. 2) Berman Economics supports Metglas' position, arguing that Metglas has demonstrated its willingness and capability to increase capacity as a result of the 2007 Final Rule and should be expected to do so again, particularly considering the
DOE is aware that there is currently only one global supplier of amorphous steel with any significant capacity and that the parent company is foreign-owned (although a substantial share of its production takes place domestically through its U.S. subsidiary). At the same time, a few other steel producers have announced plans to begin, or have recently begun, very limited production of amorphous metal. DOE is also aware that there are only a few suppliers for mechanically scribed steel and that some of these suppliers are also foreign-owned. Given the lack of suppliers of domain-refined (e.g., H0, ZDMH) and amorphous steels, DOE agrees that the amended energy conservation standards should provide manufacturers with the option to cost-effectively use grain-oriented silicon steels, which have fewer supply constraints. This would help ensure that utilities have access to transformers, particularly in the event of stronger economic growth (a driver of transformer demand) or a natural disaster, both concerns raised by commenters. Furthermore, DOE understands that M2 cannot be produced at the quantities equivalent to current M3 yields due to the nature of the silicon steel production process. Given these facts, DOE concluded that a standard that could not be achieved by M3 would not be economically justified. On the other hand, DOE also acknowledges that the current amorphous supplier may be able to expand capacity to meet additional demand and a few other companies have begun the initial stages of developing capacity. The eventual steel quality and production capacity of these emerging amorphous sources are unknown at this time. Therefore, DOE has been careful in selecting a TSL that would allow manufacturers to use not only amorphous and mechanically scribed steel,that is currently produced in limited quantities, but also grain-oriented steels.
DOE believes that the Earthjustice comment that DOE did not rationally analyze the potential impacts associated with steel production capacity constraints actually refers to two related but separate issues in the NOPR and NOPR TSD. In the TSD, DOE explains that the availability of total core steel would not be an issue until TSL 4 because both conventional and amorphous steels would be available to use until that point. In the NOPR, DOE explains that the availability of amorphous steel may be an issue at TSLs 2 and 3, and that manufacturers may need to use other types of steels, such as M3, which are not the lowest cost options. These statements are not contradictory because, although amorphous steel capacity may not be able to expand to meet all demand at TSLs 2 and 3, that does not imply that total core steel capacity would be insufficient because manufacturers still have the option of using M3 or M2 or other steels at these levels.
An important area of discussion among stakeholders is the impact of energy efficiency standards on small manufacturers. At the NOPR public meeting, ASAP had suggested that DOE should do additional work to better document and understand the scale of the impacts on small manufacturers. (ASAP, No. 146 at p. 170)
Some stakeholders expressed concern that standards higher than those proposed in the NOPR would have a significant negative impact on small manufacturers. NEMA is very concerned with the possibility that higher efficiency standards will negatively impact small manufacturing facilities and may drive some small companies, in particular LVDT transformer manufacturers, out of business. (NEMA, No. 170 at pp. 4, 8) In addition, at least one small NEMA manufacturer of liquid-immersed distribution transformers has reported that it cannot stay in business at levels higher than EL1. (NEMA, No. 170 at p. 6) APPA is also concerned about small manufacturer impacts resulting from the use of amorphous steel, stating that small transformer manufacturers that may not be able to afford or have the expertise to convert their plants to accommodate amorphous core construction may be forced to go out of business. (APPA, No. 191 at p. 5) HVOLT commented that producing stacked core products with mitering would take millions of dollars and small manufacturers in some states cannot afford that investment, and may be forced to go out of business. (HVOLT, No. 146 at pp. 50–51) Furthermore, at higher efficiency levels, even if small manufacturers can continue to use butt-lapping, they may not be able to sell their transformers at a price where material costs are recovered. (HVOLT, No. 146 at p. 151)
However, other stakeholders have suggested that small manufacturer effects have been overemphasized in DOE's analysis. ACEEE, ASAP, NRDC, and NPCC disagreed with DOE's small business analysis, claiming that it overstates impacts on small business manufacturers of LVDT transformers. The NOPR record and an investigation by the Advocates indicate that the vast majority of covered transformers are manufactured by a handful of large manufacturers with all of their major production facilities in Mexico. Since small, domestic manufacturers cannot compete on price with Mexican production facilities, domestic manufacturers focus on specialty transformers which are generally outside the scope of the regulation or on high-efficiency offerings. (Advocates, No. 186 at pp. 5–6) Furthermore, even if DOE finds that there are a significant number of small manufacturers with U.S. production facilities making covered LVDT transformers, the Advocates suggest that DOE should still adopt TSL 3 because any small manufacturer with long term viability in the distribution transformer market can build compliant transformers. DOE's record indicates that the least-cost option for building LVDT transformers at TSL 3 entails step-lap mitering and some small manufacturers already have mitering equipment. The Advocates commented that for companies that currently lack mitering machines, industry experts have testified that a step lap mitering machine costs between $0.5 million and $1 million, which is a small investment that should be well within reach for viable manufacturing companies, even if they are small. The Advocates also indicate that DOE may have placed too much emphasis on
Similar sentiments were expressed by California Investor Owned Utilities (CA IOUs). According to the CA IOUs, although DOE repeatedly emphasizes the concern that small manufacturers may be disproportionately impacted by higher standard levels and leans on this concern as justification for selecting TSL 1 for low-voltage dry-type transformers, there are actually very few small manufacturers in this market and those small manufacturers that do exist primarily focus on design lines that are exempted from coverage. The CA IOUs commented that some small manufacturers that do produce covered transformers are focusing on high efficiency NEMA Premium® transformers, indicating that smaller manufacturers are already capable of producing higher efficiency transformers. Furthermore, small manufacturers could source their cores, and many are currently doing so today, which offsets any need to upgrade core construction equipment. (CA IOUs, No. 189 at pp. 2–3)
Also, Earthjustice has commented that DOE has arbitrarily relied on impacts on small manufacturers in rejecting stronger standards for low-voltage dry-type (LVDT) units despite there being few, if any, small manufacturers of this equipment who are likely to be impacted. DOE has not explained why sourcing cores is not an acceptable option for any small manufacturer and, given the evidence in the TSD that sourcing cores is a more profitable approach for small manufacturers of LVDTs, DOE's reliance on the adverse financial impacts to small manufacturers associated with producing such cores in-house in rejecting stronger LVDT standards is unreasonable. (Earthjustice, No. 195 at pp. 3–5)
NEEP has suggested that DOE should not sacrifice large national benefits to provide ill-defined benefits for a small number of manufacturers. Even if some domestic small manufacturers may be affected by the new standards, DOE should do a more comprehensive analysis of how much the standards would impact those small manufacturers. The investments needed to meet new standards may be affordable for companies which have covered transformers as a significant part of their business, and companies that have covered transformers as a small portion of their business may choose to exit this part of the market or source their cores. (NEEP, No. 193 at pp. 4–5)
DOE understands that small companies face additional challenges from an increase in standards because they are more likely to have lower production volumes, fewer engineering resources, a lack of purchasing power for high performance steels, and less access to capital.
For liquid-immersed distribution transformers, DOE does not believe that small manufacturers will face significant capital conversion costs at TSL 1 because they can continue to produce silicon steel cores using M3 or better grades rather than invest in amorphous technology should they make that business decision. Alternatively, they could source their cores, a common industry practice.
For the LVDT market, DOE conducted further analysis based on comments received on the NOPR to reevaluate the impact of higher standards on small manufacturers. Although there may not be many small LVDT manufacturers that produce covered equipment in the U.S. and small manufacturers may hold only a low percentage of market share, the Department of Energy does consider impacts on small manufacturers to be a significant factor in determining an appropriate standard level. As discussed in the engineering analysis, because commenters suggested that EL3, the efficiency level selected at TSL 2 for DL7 (equivalent to NEMA Premium®), could be achieved with a butt-lap design, DOE further investigated the efficiency limits of butt-lapping potential. The primary reason that DOE proposed TSL 1 over TSL 2 in the NOPR was because it did not appear that TSL 2 could be met using butt-lapping technology, which would have caused undue hardship on small manufacturers that utilize this technology. However, in response to comments from the NOPR, DOE analyzed additional design option combinations using butt-lapping technology for DL 7 in its engineering analysis and determined that EL 3 can still be achieved without the need for mitering by using higher grade steels. While these would likely not be the designs of choice for high-volume manufacturers because the capital cost of a mitering machine has a much lower per unit cost given their larger volumes, this option may allow low-volume players, such as small manufacturers, to avoid investing in mitering machines or sourcing their cores due to financial constraints. However, at TSL 3 and higher, manufacturers may not be able to continue using butt-lapping technology with steels that are readily available.
Although sourced cores may be the most cost-effective strategy in the near term, some manufacturers indicated during interviews that production of cores is an important part of the value chain and that they could ill-afford to cede it to third parties. On the other hand, some manufacturers indicated they are able to successfully compete because of their sourcing strategies, not in spite of them, because they can meet a variety of customer needs more quickly and cheaply than would otherwise be possible. Particularly because most small U.S. LVDT manufacturers are heavily involved in the transformer market not otherwise covered by statute, which constitutes roughly 50 percent of all LVDT sales, DOE believes that sourcing DOE-covered mitered cores represents a viable strategic alternative for small LVDT manufacturers, given that it is a common industry business strategy for low volume product lines.
In conclusion, DOE believes that TSL 2, the level established by today's standards, affords small LVDT transformer manufacturers with several strategic paths to compliance: (1) Investing in mitering capability, (2) continuing to use low-capital butt-lap core designs with higher grade steels, (3) sourcing cores from third-party core manufacturers, or (4) focus on the exempt portion of the market.
Berman Economics questioned DOE's methodology for calculating conversion costs, which was described in section IV.I.3.c of the NOPR. Berman argued that DOE provided unreasonable estimates of conversion costs because DOE based estimates on an arbitrary percent of total R&D expenditures across all equipment regulated by DOE. Therefore, the conversion cost estimates are not relevant to the proposed regulatory action. (Berman Economics, No. 150 at pp. 14–15)
In response, the percentages that DOE used to determine product conversion costs for liquid-immersed transformer
Berman Economics also commented that DOE's estimates of stranded assets were illogical for production, financial, and corporate strategy reasons. From a production perspective, there is likely to be a net increase in demand for silicon steel at EL 2 for liquid-immersed transformers so assets such as annealing ovens would not be stranded. Berman Economics stated most annealing ovens are very old and have already been depreciated, and manufacturing investment may be expensed in the year purchased according to current tax laws, so the cost of all recently purchased annealing ovens has already been recovered. From a strategic perspective, if a manufacturer chooses not to offer an amorphous line of products, DOE should not put itself in a position to favor that manufacturer's strategy over another. Furthermore, Berman Economics stated that DOE based stranded assets on an arbitrary percent of new capital conversion costs which may have been a holdover from the decision on microwave ovens. (Berman Economics, No. 150 at pp. 15–16)
DOE agrees that the calculations in the NOPR for stranded assets were incorrectly derived in the GRIM and has revised the model for the final rule. For the final rule, stranded assets in the standards case are derived from the share of the industry's net property, plant and equipment (PPE) that is estimated to no longer be useful due to energy conservation standards. The change has no substantial effect on the overall results. See TSD chapter 12 for more details.
Berman Economics also stated that DOE has overestimated capital conversion costs because the Department assumed a 100 percent front-load in investment prior to the 2016 effective date rather than a least-cost method of financing, such as a long-term loan. (Berman Economics, No. 150 at p. 16)
Accounting for investments in the time frame between the effective date of today's rule and the rule compliance date is the accepted methodology vetted during the preliminary analysis and the standard model used for DOE rulemakings. This methodology also considers the possibility that some manufacturers, such as small manufacturers, may have difficulty obtaining loans.
In addition, Berman Economics argued that an increased market demand for amorphous steel relative to silicon steel may reduce investment expenditures rather than increase them because the annealing oven for an amorphous steel core costs substantially less than the annealing oven for a silicon steel core. Some transformer manufacturers may also be able to source cores, which, Berman Economics stated, DOE incorrectly considered an undesirable market activity. Berman Economics noted that an outsourcing opportunity allows manufacturers to specialize, use cash for other strategic purposes, and pursue multiple objectives. (Berman Economics, No. 150 at pp. 16–17)
DOE takes into account conversion costs associated with a given TSL. While the cost of a single annealing oven for an amorphous steel core may be less than the cost of a single annealing oven for a silicon steel core, other factors, particularly throughput levels, associated tooling, and the R&D expenses allocated to the development of new designs and production processes, also drive conversion costs calculations.
With respect to core sourcing, as with the above discussion related to the LVDT market, DOE notes that it is not making any judgment on the value of one business strategy versus another. Whether sourcing cores is a viable option for any given manufacturer is a decision for each manufacturer in the context of its unique environment. However, during interviews, some manufacturers indicated that production of cores is an important part of the value chain and doubted their long-term viability should they outsource that function.
Finally, Berman Economics has noted that the logic explained by DOE that more stringent levels of efficiency are associated with larger adverse industry impacts does not hold true in the GRIM, which indicates that the model contains a multiplicity of unknown logic errors and its results must be viewed as spurious. (Berman Economics, No. 150 at p. 18)
Although higher efficiency levels are often correlated with greater adverse industry impacts, certain offsetting factors based on DOE's markup assumptions may result in deviations from this pattern. For example, in the preservation of gross margin percentage scenario, DOE applied a single uniform “gross margin percentage” markup across all efficiency levels so that, as production costs increase with efficiency, the absolute dollar markup increases as well. Therefore, the highest efficiency levels do not result in the highest drop in INPV because manufacturers are able to compensate for higher conversion costs by charging higher prices.
DOE interviewed manufacturers representing approximately 65 percent of liquid-immersed distribution transformer sales, 75 percent of medium-voltage dry-type transformer sales, and 50 percent of low-voltage dry-type transformer sales. These interviews were in addition to those DOE conducted as part of the engineering analysis. DOE outlined the key issues for the rulemaking for manufacturers in the NOPR. 77 FR 7282 (February 10, 2012). DOE considered the information received during these interviews in the development of the NOPR and this final rule.
DOE identified small manufacturers as a subgroup in the MIA. DOE describes the impacts on small manufacturers in section VI.B. below.
Employment impacts include direct and indirect impacts. Direct employment impacts are any changes in the number of employees of manufacturers of the equipment subject to standards, their suppliers, and related service firms. The MIA addresses those impacts. Indirect employment impacts are changes in national employment that occur due to the shift in expenditures and capital investment caused by the purchase and operation of more efficient appliances. Indirect employment impacts from standards consist of the jobs created or eliminated in the national economy, other than in the manufacturing sector being regulated, due to: (1) Reduced spending by end users on energy; (2) reduced spending on new energy supply by the utility industry; (3) increased consumer spending on the purchase of new equipment; and (4) the effects of those three factors throughout the economy. DOE's employment impact analysis addresses these impacts. No public comments were received on this analysis.
One method for assessing the possible effects on the demand for labor of such shifts in economic activity is to compare sector employment statistics developed by the Labor Department's Bureau of Labor Statistics (BLS). BLS regularly publishes its estimates of the number of jobs per million dollars of economic activity in different sectors of the economy, as well as the jobs created elsewhere in the economy by this same economic activity. Data from BLS indicate that expenditures in the utility sector generally create fewer jobs (both directly and indirectly) than expenditures in other sectors of the economy.
For the standard levels considered in today's final rule, DOE estimated indirect national employment impacts using an input/output model of the U.S. economy called Impact of Sector Energy Technologies version 3.1.1 (ImSET). ImSET is a special-purpose version of the “U.S. Benchmark National Input-Output” (I–O) model, which was designed to estimate the national employment and income effects of energy-saving technologies. The ImSET software includes a computer-based I–O model having structural coefficients that characterize economic flows among the 187 sectors. ImSET's national economic I–O structure is based on a 2002 U.S. benchmark table, specially aggregated to the 187 sectors most relevant to industrial, commercial, and residential building energy use. DOE notes that ImSET is not a general equilibrium forecasting model, and understands the uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Because ImSET does not incorporate price changes, the employment effects predicted by ImSET may over-estimate actual job impacts over the long run. For the final rule, DOE used ImSET only to estimate short-term employment impacts.
For more details on the employment impact analysis, see chapter 13 of the final rule TSD.
The utility impact analysis estimates several important effects on the utility industry that would result from the adoption of new or amended standards. To calculate this, DOE first obtained the energy savings inputs associated with efficiency improvements to the considered products from the NIA. Then, DOE used that data in the NEMS–BT model to generate forecasts of electricity consumption, electricity generation by plant type, and electric generating capacity by plant type, that would result from each TSL. Finally, DOE calculates the utility impact analysis by comparing the results at each TSL to the latest
Chapter 14 of the final rule TSD describes the utility impact analysis. No public comments were received on this analysis.
In the emissions analysis, DOE estimated the reduction in power sector emissions of CO
SO
The attainment of emissions caps typically is flexible among EGUs and is enforced through the use of emissions allowances and tradable permits. Under existing EPA regulations, any excess SO
Beginning in 2015, however, SO
Under CSAPR, there is a cap on NO
The MATS limit mercury emissions from power plants, but they do not include emissions caps and, as such, DOE's energy conservation standards would likely reduce Hg emissions. For this rulemaking, DOE estimated mercury emissions reductions using the NEMS–BT based on
Chapter 15 of the final rule TSD provides further information on the emissions analysis.
As part of the development of this rule, DOE considered the estimated monetary benefits from the reduced emissions of CO
For CO
Under section 1(b)(6) of Executive Order 12866, 58 FR 51735 (Oct. 4, 1993), agencies must, to the extent permitted by law, “assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs.” The purpose of the SCC estimates presented here is to allow agencies to incorporate the monetized social benefits of reducing CO
As part of the interagency process that developed the SCC estimates, technical experts from numerous agencies met on a regular basis to consider public comments, explore the technical literature in relevant fields, and discuss key model inputs and assumptions. The main objective of this process was to develop a range of SCC values using a defensible set of input assumptions grounded in the existing scientific and economic literatures. In this way, key uncertainties and model differences transparently and consistently inform the range of SCC estimates used in the rulemaking process.
The SCC is an estimate of the monetized damages associated with an incremental increase in carbon dioxide emissions in a given year. It is intended to include (but is not limited to) changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services. Estimates of the SCC are provided in dollars per metric ton of carbon dioxide.
When attempting to assess the incremental economic impacts of carbon dioxide emissions, the analyst faces a number of serious challenges. A recent report from the National Research Council
Despite the serious limits of both quantification and monetization, SCC estimates can be useful in estimating the social benefits of reducing carbon dioxide emissions. Consistent with the directive quoted above, the purpose of the SCC estimates presented here is to make it possible for agencies to incorporate the social benefits from reducing carbon dioxide emissions into cost-benefit analyses of regulatory actions that have small, or “marginal,” impacts on cumulative global emissions. Most Federal regulatory actions can be expected to have marginal impacts on global emissions.
For such policies, the agency can estimate the benefits from reduced (or costs from increased) emissions in any future year by multiplying the change in emissions in that year by the SCC value appropriate for that year. The net present value of the benefits can then be calculated by multiplying each of these future benefits by an appropriate discount factor and summing across all affected years. This approach assumes that the marginal damages from increased emissions are constant for small departures from the baseline emissions path, an approximation that is reasonable for policies that have effects on emissions that are small relative to cumulative global carbon dioxide emissions. For policies that have a large (non-marginal) impact on global cumulative emissions, there is a separate question of whether the SCC is an appropriate tool for calculating the benefits of reduced emissions. This concern is not applicable to this rulemaking, and DOE does not attempt to answer that question here.
It is important to emphasize that the interagency process is committed to updating these estimates as the science and economic understanding of climate change and its impacts on society improves over time. Specifically, the interagency group has set a preliminary goal of revisiting the SCC values at such time as substantially updated models become available, and to continue to support research in this area. In the meantime, the interagency group will continue to explore the issues raised by this analysis and consider public comments as part of the ongoing interagency process.
To date, economic analyses for Federal regulations have used a wide range of values to estimate the benefits associated with reducing carbon dioxide emissions. In the model year 2011 CAFE final rule, the Department of Transportation (DOT) used both a “domestic” SCC value of $2 per metric ton of CO
A 2008 regulation proposed by DOT assumed a domestic SCC value of $7 per metric ton of CO
In 2009, an interagency process was initiated to offer a preliminary assessment of how best to quantify the benefits from reducing carbon dioxide emissions. To ensure consistency in how benefits are evaluated across agencies, the Administration sought to develop a transparent and defensible method, specifically designed for the rulemaking process, to quantify avoided climate change damages from reduced CO
Since the release of the interim values, the interagency group reconvened on a regular basis to generate improved SCC estimates, which were considered for this proposed rule. Specifically, the group considered public comments and further explored the technical literature in relevant fields. The interagency group relied on three integrated assessment models (IAMs) commonly used to estimate the SCC: The FUND, DICE, and PAGE models.
Each model takes a slightly different approach to model how changes in emissions result in changes in economic damages. A key objective of the interagency process was to enable a consistent exploration of the three models while respecting the different approaches to quantifying damages taken by the key modelers in the field. An extensive review of the literature was conducted to select four sets of input parameters for these models: Climate sensitivity, socio-economic and emissions trajectories, and discount rates. A probability distribution for climate sensitivity was specified as an input into all three models. In addition, the interagency group used a range of scenarios for the socio-economic parameters and a range of values for the discount rate. All other model features were left unchanged, relying on the model developers' best estimates and judgments.
The interagency group selected four SCC values for use in regulatory analyses. Three values are based on the average SCC from three integrated assessment models, at discount rates of 2.5 percent, 3 percent, and 5 percent. The fourth value, which represents the 95th percentile SCC estimate across all three models at a 3-percent discount rate, is included to represent higher-than-expected impacts from temperature change further out in the tails of the SCC distribution. For emissions (or emission reductions) that occur in later years, these values grow over time, as depicted in Table IV.9. Additionally, the interagency group determined that a range of values from 7 percent to 23 percent should be used to adjust the global SCC to calculate domestic effects,
It is important to recognize that a number of key uncertainties remain, and that current SCC estimates should be treated as provisional and revisable since they will evolve with improved scientific and economic understanding. The interagency group also recognizes that the existing models are imperfect and incomplete. The National Research Council report mentioned above points out that there is tension between the goal of producing quantified estimates of the economic damages from an incremental metric ton of carbon and the limits of existing efforts to model these effects. There are a number of concerns and problems that should be addressed by the research community, including research programs housed in many of the agencies participating in the interagency process to estimate the SCC.
DOE recognizes the uncertainties embedded in the estimates of the SCC used for cost-benefit analyses. As such, DOE and others in the U.S. Government intend to periodically review and reconsider those estimates to reflect increasing knowledge of the science and economics of climate impacts, as well as improvements in modeling. In this context, statements recognizing the limitations of the analysis and calling for further research take on exceptional significance.
In summary, in considering the potential global benefits resulting from reduced CO
As noted above, new or amended energy conservation standards would reduce NO
Commenting on the NOPR, APPA stated that DOE has significantly overstated the environmental benefits from NO
In response, DOE disagrees with APPA's claim that “[t]hese emissions markets and their subsequent prices were designed to monetize the environmental cost of polluting in its entirety.” Emissions allowance prices in any given market are a function of several factors, including the stringency of the regulations and the costs of complying with regulations, as well as the initial allocation of allowances. The prices do not reflect the potential damages caused by emissions that still take place. There is extensive literature on valuation of benefits of reducing air pollutants, including valuation of reduced NO
DOE has decided to await further guidance regarding consistent valuation and reporting of Hg emissions before it monetizes Hg in its rulemakings.
In the NOPR, DOE responded to comments regarding the classification and labeling of rectifier and testing transformers. In response to these comments, DOE acknowledged that the proposed additions to the definitions helped to clarify “rectifier” and “testing transformers” and proposed to amend the definitions accordingly.
Cooper Power expressed support for the plan DOE set forth in the NOPR to clarify rectifier and testing transformers. (Cooper, No. 165 at p. 2) Howard Industries also expressed support, noting that while they do not manufacture rectifier or testing transformers, they find DOE's nameplate request to “indicate that they are for such purposes exclusively” to be acceptable. (HI, No. 151 at p. 12) Earthjustice commented that the addition of labeling requirements for rectifier and testing transformers can help prevent misapplication of these exempt products, but they feel additional changes, such as requiring any print or electronic marketing for such units to indicate their use specifically, may also be necessary to ensure enforcement. (Earthjustice, No. 195 at p. 5; Earthjustice No. 146 at p. 44) However, Progress Energy commented that rectifier and testing transformers are already very specialized and usually more expensive than distribution transformers; therefore, there is a very low chance of a utility attempting to replace a distribution transformer with one of these transformers. (PE, No. 192 at p. 4) APPA concurred, noting that they were unaware of rectifier or testing transformers being used as a loophole. (APPA, No. 191 at p. 6) Similarly, HVOLT pointed out that the physical differences between rectifier and distribution transformers would be fairly obvious without a nameplate marking. Furthermore, they feel that adding the word “rectifier” to the nameplate would only add more congestion. (HVOLT, No. 146 at p. 46)
In response to the NOPR, many stakeholders expressed their support for clearly identifying transformers excluded from DOE standards through a standardized labeling system. ABB recommended that the text “DOE Excluded: Transformer type” be included on the nameplate for all of the excluded type transformers, and suggested that this labeling requirement be added to CFR part 429. (ABB, No. 158 at p. 5) ABB also noted that they agree with the proposal to not set standards for step-up transformers, and that all step-up transformers be identified on the nameplate with uniform language. (ABB, No. 158 at p. 6) NEMA agreed with ABB, stating that “labeling should be applied in a consistent manner for all designated non-regulated distribution transformers” and suggested the following language be used: “This _____Transformer is NOT intended for use as a Distribution Transformer per 10 CFR 431.192” (NEMA, No. 170 at p. 7) Prolec-GE and PEMCO expressed similar ideas, both commenting that all excluded transformers should be identified by type and indicate that they are excluded from standards. (PEMCO, No. 183 at p. 2; Prolec-GE, No. 177 at p. 7) Schneider concurred, stating “all non-regulated transformers should require labeling—not just rectifier and testing transformers.” (Schneider, No. 180 at p.3)
Prolec-GE encouraged DOE to establish labeling requirements or guidelines for covered products for use in the United States. They believed that, at present, without specifications for labeling products, those charged with certification, compliance and enforcement would have difficulty identifying which products were to meet which standards a difficult time with inconsistent labeling. (Prolec-GE, No. 177 at pp. 16–17) Schneider Electric also expressed that regulated products should have labeling rules with the following language “DOE 10 CFR PART 431 COMPLIANT.” Schneider would also like DOE certification regulations (10 CFR part 429) expanded to include non-regulated products. (Schneider, No. 180 at p. 3)
GE commented that refurbished units should be labeled as such and have the original manufacturer's nameplate removed. (GE, No. 146 at p. 114)
DOE had initially considered amending the definitions of “rectifier transformer” and “testing transformer” to include a labeling requirement. Commenters, however, have pointed out that a number of transformer types would benefit from a clear set of labeling requirements, which could aid manufacturers, consumers, and DOE itself in determining whether a given sample is covered or determined by the manufacturer as meeting the standards. Given the breadth of the issue, DOE makes no changes to labeling requirements in today's rule, but may address the matter of distribution transformer labeling in a future rulemaking. DOE appreciates the comments and feedback regarding labeling supplied by the stakeholders. Issues regarding labeling, compliance, and enforcement may, however, be considered in a different proceeding.
Comments DOE received in response to the NOPR analysis on the soundness and validity of the methodologies and data DOE used are discussed in previous parts of section IV. Other stakeholder comments in response to the NOPR addressed specific issues associated with amended standards for transformers. DOE addresses these other comments below.
DOE created TSLs that each consist of specific efficiency levels for a set of design lines. For the NOPR, DOE examined seven TSLs for liquid-immersed distribution transformers, six TSLs for low-voltage dry-type distribution transformers, and five TSLs for medium-voltage dry-type distribution transformers.
For liquid-immersed distribution transformers, joint comments submitted by ASAP, ACEEE, NRDC and NPCC recommended that DOE modify TSL 4 to represent their collective final position from the Negotiated Rulemaking, which advocated including EL 2 for all liquid-immersed distribution transformer design lines. (In the NOPR, DOE misstated and analyzed the Advocates collective final position from the Negotiated Rulemaking as EL3 for all liquid-immersed distribution transformer design lines.). They also recommended that DOE examine a TSL 3.5 level, which would correspond to EL 1.5 across the board. (ASAP, ACEEE, NRDC, NPCC, No. 186 at p. 9)
In response to these comments DOE considered four new TSLs, labeled A, B, C and D, to explore possible energy savings below EL 2. TSL C, consisting of EL 2 for all liquid-immersed distribution transformer design lines, correctly represents the collective final position of ASAP, ACEEE, NRDC, and NPCC in the negotiations. DOE presented these new TSLs to stakeholders at a public meeting on June 20, 2012.
Several parties stated that these new TSLs, while being technologically feasible, would present issues due to increased transformer size and weight. NRECA, Howard Industries, and NEMA stated that this issue would increase the frequency of pole replacement by utilities. (NRECA, No. 228 at p. 2; HI, No. 218 at p.1; NEMA, No. 225 at p. 6) Central Maloney commented that their designs at the new TSLs exceeded customer weight specifications for their single-phase, pole-mounted distribution transformers at various kVA capacities. (CM, No. 224 at p.3) Others stated that the economic benefits of TSLs B through D could only be realized with core steels other than M3 (NEMA, No. 225 at pp. 4, 5; ATI No. 218 at p. 1), which could transfer significant market power to producers of SA1 core steel (AK, No. 230 at p. 4) and lead to unintended anti-competitive results. (ATI, No. 218 at p. 1; AK, No. 230 at p. 5)
DOE concluded that all of these new TSLs would result in similar burdens as
ASAP, ACEEE, NRDC and NPCC stated that DOE has not evaluated the potential impacts of the proposed standards for liquid-immersed distribution transformers since the proposed standard levels are not the same as the levels in TSL 1 for equipment class 1. They said that DOE's final standard must be based on analysis and results for the actual efficiency levels established by the final rule. (ASAP, ACEEE, NRDC, NPCC, No. 186 at p. 9) Similarly, NEEP stated that the proposed TSL 1 for liquid-immersed distribution transformers did not have all the corresponding ELs for the various design lines. It noted that DOE proposed 98.95 percent for design line 2, which does not correspond to any EL. (NEEP, No. 193 at p. 2)
In response to these comments, for this final rule, DOE analyzed the actual efficiency ratings proposed in the NOPR for equipment class 1 (single-phase liquid-immersed transformers) at TSL 1. These efficiencies are 99.11 percent for design line 1, 98.95 percent for design line 2, and 99.49 percent for design line 3. These efficiencies correspond to EL 0.4 for design line 1, EL 0.5 for design line 2, and EL 1.1 for design line 3.
The TSLs that DOE used for the final rule are presented in section V.A of this preamble. DOE notes that, for the final rule, it has slightly modified the definition of TSL 2 for low-voltage dry-type distribution transformers from the NOPR definition. Where previously DL 6 had been at EL 3 in TSL 2, in today's rule DL 6 is held at the baseline because DOE did not find positive economic benefits to the consumer above that level. Small, single-phase transformers tend to be lightly-loaded and have a more difficult time than their larger, three-phase counterparts recovering increases in first cost. DOE believes this change provides increased customer benefits with TSL 2.
A number of parties expressed concern that amended standards on transformers would induce use of rebuilt or refurbished distribution transformers rather than the more expensive new transformers. (HI, No.151 at pp. 9, 12; Cooper, No. 165 at p. 5; Prolec-GE, No. 177 at p. 14; ComEd, No. 184 at p. 13; Westar, No. 169 at p. 3) Several parties stated that the higher the initial cost increase due to energy efficiency standards, the higher the likelihood that utilities will use more recycled equipment. (EEI, No. 185 at p. 17; APPA, No. 191 at p. 12; Progress Energy, No. 192 at p. 9) BG&E stated that if new transformer requirements significantly increase costs, it may consider purchasing refurbished designs to address the size and weight problems of transformers meeting the standard. (BG&E, No. 182 at p. 9) Fort Collins Utilities commented that it would be purchasing fewer new transformers and re-winding more of its existing transformer units. (CFCU, No. 190 at p. 3)
Some parties specifically stated that setting standards for liquid-immersed distribution transformers greater than TSL 1 would increase the use of less-efficient, refurbished transformers, and this would reduce the energy savings from such standards. (NEMA, No. 170 at p. 3; USW, No. 188 at pp. 4, 18–19) AEC and NRECA stated that if DOE raises standards above the levels proposed in the NOPR, it is likely that costs will increase dramatically, increasing the likelihood that more existing transformers will be recycled via refurbishment, rewinding, or rebuilding. (AEC, No. 163 at p. 3; NRECA, No. 172 at p. 3)
Several parties stated that rebuilt or refurbished transformers would be less efficient than new transformers and, therefore, the energy saving goals of standards would be undermined. (HI, No. 151 at pp. 9, 12; Cooper, No. 165 at p. 5; Prolec-GE, No. 177 at p. 14) AEC and NRECA stated that, in some cases, the efficiency of transformers may actually increase as a result of refurbishment or rewinding, but the efficiency of the refurbished transformer will most likely not meet the proposed efficiency levels. (AEC, No. 163 at p. 3; NRECA, No. 172 at p. 3) HI requested that DOE seek authority over the refurbished/repair industry to minimize use of lower-efficiency transformers. (HI, No. 151 at p. 11)
DOE acknowledges that a significant increase in the cost of new transformers could encourage growth in the use of refurbished transformers by some utilities, and that refurbished transformers likely would be less efficient than new transformers meeting today's standards. Although DOE was not able to explicitly model the likely extent of refurbishing at each considered TSL, it did include in its shipments analysis a price elasticity parameter that captures the response of the market to higher costs in a general way (see chapter 9 of the final rule TSD). Furthermore, DOE believes that the costs of new transformers meeting today's standards, which are approximately 3.0 percent (design line 2) and 13.1 percent (design line 3) higher than today's typical single-phase liquid-immersed distribution transformers, and approximately 6.9 percent (design line 4) and 12.6 percent (design line 5) higher than today's typical three-phase liquid-immersed transformers, would not be so high as to induce a significant level of refurbishing instead of replacement.
Earthjustice asserted that “the statute leaves room for DOE to regulate the efficiency of rebuilt transformers” and that “it is reasonable for DOE to determine that rewound transformers are `new covered products' subject to energy conservation standards if the title of the rewound transformer is then transferred to an end-user.” (Earthjustice No. 195 at p. 6) Other commenters reached opposite conclusions regarding whether DOE has the authority to regulate refurbished or rewound transformers. AEC agreed with statements made by DOE's Office of the General Counsel during negotiations that existing and recycled transformers are not “covered” equipment and would not have to meet the proposed energy efficiency standards for new products that are “covered.” (AEC No. 163 at p. 3)
DOE has analyzed this issue for many years. For instance, in its August 4, 2006, NOPR, DOE summarized its legal authority to regulate new, used and refurbished transformers and sought public comment on the issue. 71 FR 44356, 44366–67. In that notice, DOE noted that for the entire history of its appliance and commercial equipment energy conservation standards program, DOE has not sought to regulate used
Rockwood Electric commented that a more effective means of saving energy than requiring energy conservation in the distribution transformers themselves would be to require that power distribution occur at higher voltages and thereby reduce resistive losses. (Rockwood Electric, No. 167 at p. 1) CFCU advocated that DOE seek more cost-effective means of finding efficiency in electric distribution systems than by increasing efficiency standards for distribution transformers. (CFCU, No. 190 at p. 2) DOE has no plans to address distribution voltage ratings in the present rulemaking, and does not consider the possibility to fall within its scope of coverage.
Prior to publication of the NOPR, DOE held a series of negotiating sessions to discuss standards for all three types of distribution transformer under the Negotiated Rulemaking Act. The negotiating parties succeeded in arriving at a consensus standard for medium-voltage dry-type transformers, which is adopted in today's rule. Such adoption was supported by a broad spectrum of parties as discussed previously (Advocates, 4/10/12 comment at p. 2) Several parties commented on the negotiated rulemaking process.
Despite praising the consensus agreement on the medium-voltage-dry-type units, the Advocates commented that overall the process “produced virtually no benefits.” (Advocates, No. 186 at p. 14) In contrast, NEMA commented that the process was extremely valuable and resulted in a better analysis. (NEMA, No. 170 at p. 2) Eaton remarked that the negotiation process improved the resulting proposal for LVDT distribution transformers and was a more efficient vehicle for considering stakeholder input. (Eaton, No. 157 at p. 2) Progress Energy recommended that the spirit of the negotiating committee be retained indefinitely through formation of a task force of stakeholders that could advise DOE in the future. (PE, No. 192 at p. 2)
DOE appreciates feedback on the negotiation process and will consider its use in appropriate future rulemakings. Currently, DOE has no plans to form a task force on distribution transformer standards.
DOE received many comments that supported or criticized the Department's weighing of the benefits and burdens in its selection of the proposed levels, particularly for liquid-immersed and low-voltage dry type transformers. The first section below presents general comments on all of the transformer superclasses, and the following sections present comments specifically on each of the superclasses. The final section presents a response to the comments by DOE.
Many stakeholders expressed their support for the standards proposed by DOE. (AK, No. 146 at p. 143; ATI, No. 146 at p. 7; ATI, No. 181 at p. 1–2; CDA, No. 153 at p. 1; ComEd, No. 184 at p. 1; Cooper, No. 165 at p. 1; DE, No. 179 at p. 1; JEC, No. 173 at p. 2; KAEC, No. 126 at p. 1–2; KAEC, No. 149 at p. 7; NEMA, No. 146 at p. 146; NRECA, No. 146 at p. 158; PECO, No. 196 at p. 1; UAW, No. 194 at p. 1; USW, No. 148 at p. 1; Adams Electrical Coop, No. 13) Others pointed out that these levels are well-balanced, allowing cold rolled grain-oriented steel (CRGO)/amorphous competition, energy savings, and benefits to consumers without unduly harming manufacturers. (ATI, No. 146 at p. 9; Cooper, No. 143 at p. 1; Cooper, No. 146 at p. 13–14; (FedPac, No. 132 at p. 1 and pp. 3–4; HVOLT, No. 144 at p. 1 and pp. 10–11; NEMA, No. 146 at p. 12–13; Prolec-GE, No. 146 at p. 14–15; Schneider, No. 180 at p. 1; USW, No. 148 at p. 1) Other parties agreed, noting that a higher standard would cause a transition to amorphous steel, and urged DOE not to move to higher standard levels, as the proposed standards are the highest justified levels. (USW, No. 148 at p. 2; Weststar, No. 169 at p. 1 and p. 4; Adams Electrical Coop, No. 163 at p. 1; APPA, No. 191 at p. 2; Steelmakers, No. 188 at p. 2; PECO, No. 196 at p. 1; NEMA, No. 170 at p. 2; MTEMC, No. 210 at p. 1; EEI, No. 185 at p. 2; BG&E, No. 182 at p. 2; BSE, No. 152 at p. 1) ATI agreed, noting that the NOPR efficiency levels are the proper levels to ensure M3 and amorphous metals are cost competitive with each other. (ATI No. 181 at p. 2) KAEC commented that increased standards could pose a threat to small manufacturers. (KAEC, No. 126 at p. 2) BSE commented that an increase in standards would increase the capital expense of the transformer, which will in turn have a negative impact on rates that consumers are charged for their electricity with very minimal gains in efficiency. (BSE, No. 152 at p. 1) NEMA noted that there are no utility problems at the current proposed levels. (NEMA, No. 170 at p. 13) Steelmakers commented that DOE's proposal for liquid-immersed transformers correctly states that the standards it is proposing will not lessen the utility or performance of distribution transformers, while noting that increasing standards would negatively impact utility. (Steelmakers, No. 188 at pp. 15–16) AEC and NRECA both noted that under any revised analysis, DOE should not consider increasing the proposed efficiency levels, as the evidence has shown that there would be many negative impacts on domestic steelmakers, domestic transformer manufacturers, electric utilities, and end-use customers. (AEC, No. 163 at p. 1; NRECA, No. 172 at pp. 2, 6) NRECA supported the proposed efficiency levels in the NOPR as they minimize the concerns associated with size and weight issues. (NRECA, No. 172 at p. 8) APPA members recommend that the proposed efficiency levels should be viewed as the maximum achievable levels. (APPA, No. 191 at p. 2)
Other parties believe that DOE should choose more stringent efficiency levels. ASAP, ACEEE, NRDC and NPCC stated that a more thorough consideration of the record and completion of critical missing or incomplete analyses will lead DOE to the conclusion that higher standards are justified for both low-voltage dry-type and medium-voltage liquid-immersed transformers. They stated that higher standards than those
EMS Consulting commented that DOE's rationale for setting lower standards to minimize impact on the distribution transformer industry will cost the country significant potential energy savings and recommended higher standards for both liquid-immersed and low-voltage dry-type transformers. Based on EMS' calculations, a standard set between EL 1.5 and EL 2 for liquid-immersed transformers would allow the nation to gain additional energy savings while increasing demand for grain-oriented steels and creating a new market for amorphous steel. The market for grain-oriented steels will also expand as a result of higher standards for low-voltage dry-type transformers, which may be able to achieve EL 3 with M4/M5 material and butt-lap cores or EL 4 with step-lap mitering, and the investment required by industry to meet EL 4 is well-justified considering benefits to end users. (EMS, No. 178 at p. 8)
Some stakeholders commented that the proposed standards were too high and were not economically justified. (WE, No. 168 at p. 1,3; Sioux Valley Energy, No. 159 at p. 1; Polk-Burnett Electric Cooperative, No. 175 at p. 1; PJE, No. 202 at p. 1; MEC, No. 161 at p. 1; East Miss. EPA, No. 166 at p. 1; Central Electric Power Coop, No. 176 at p. 1) Specifically, stakeholders noted that the proposed standards would cause hardships to electricity consumers. (KEC, No. 164 at p. 1; BEC, No. 204 at p. 1; BEC, No. 205 at p. 1; CHELCO, No. 203 at p. 1) East Central Energy agreed, noting that the proposed standards achieve little to no benefit and would cost extra for manufacturers. (East Central Energy, No. 160 at p. 1) BEC pointed out that the cost savings were overstated in the NOPR. (BEC, No. 205 at p. 1) Westar Energy commented that they were hesitant to support even an increase to EL1 for liquid-immersed units. (Westar, No. 169 at p. 1) CCED noted that the standards proposed in the NOPR were without merit and the existing 2010 standards should be maintained instead. (CCED, No. 174 at p. 3)
Some stakeholders expressed opinions about how steel availability should factor into the standards that DOE chooses. Progress Energy urged DOE not to set a standard that would result in the use of specific steels that have questionable supply availability, noting that M3 and M4 grades of core steel should be required for 85 percent or more of any required efficiency level. (PE, No. 192 at p. 7–8) Earthjustice felt that DOE failed to rationally analyze the potential impacts associated with steel production capacity constraints while deciding on standard levels. (Earthjustice, No. 195 at p. 1) The Advocates noted that in the long term, amorphous steel is likely to predominate in the transformer market due to higher efficiency. They commented that countries such as China and India are fostering a transition to highly efficient transformers and more amorphous steel is used in these countries than in the United States. (Advocates, No. 186 at pp. 13–14)
The Advocates felt that DOE emphasized the worst-case scenario for manufacturer impacts when rejecting TSL 2 and TSL 3 for liquid-immersed transformers. (Advocates, No. 186 at p. 12) They noted that at TSL 4 for liquid-immersed transformers, potential costs to manufacturers are still far less than potential benefits to consumers. (Advocates, No. 186 at p. 11) The Advocates stated that DOE estimates that TSL 4 could result in a potential loss of industry value of 12 percent under the “maintenance of profits” scenario, a potential impact well within the norm of DOE estimates for other standards rulemakings. (Advocates, No. 186 at p. 3) The Advocates stated that a standard in the range of TSL 3.5 to TSL 4 would promote robust competition between silicon steel and amorphous metal, maximizing benefits for consumers and producing much larger energy savings for the Nation. They stated that TSL 4 or 3.5 can be met even if amorphous metal supplies do not increase. They added that if DOE feels that more time would provide greater confidence that supply of amorphous steel could increase to help meet market needs triggered by a TSL 3.5 or TSL 4 standard, they would not object to moving the effective date of today's rule a year or two further into the future. (Advocates, No. 186 at pp. 9–11)
At the NOPR public meeting, ASAP commented that the standard levels proposed for liquid-immersed transformers are far below the point that would maximize consumer benefits because DOE put an inordinate amount of weight on manufacturer impacts to the detriment of consumer benefits. (ASAP, No. 146 at p. 27) They also commented that DOE placed significant weight on steel manufacturer impacts but did not conduct a more detailed analysis on those impacts, in particular one which includes employment at each TSL for steel manufacturers. (ASAP, No. 146 at p. 143) ASAP recommended that DOE select EL 2 for liquid-immersed units. (ASAP, No. 146 at p. 18)
Berman Economics stated that DOE's rationale for choosing TSL 1 for liquid-immersed transformers, that a higher standard would require an unacceptable increase in cost to industry, suggests that DOE prefers that consumers pay more money than to require additional investment on the part of manufacturers. (Berman Economics, No. 150 at p. 2–3) Berman Economics also argues that DOE's rejection of EL 2 for liquid-immersed transformers is an indication that DOE is focused on avoiding competition for silicon steel even at the cost of energy and consumer savings and environmental preservation. (Berman Economics, No. 150 at p. 4) EMS recommended a level between EL 1.5 and EL 2.0. (EMS, No. 178 at p. 7)
Several stakeholders felt that DOE relied on impacts on small manufacturers too heavily, and noted that small manufacturers can build up to TSL 3. (Earthjustice, No. 195 at p. 2; Advocates, No. 186 at p. 11; NEEP, No. 193 at p. 1; ASAP, No. 146 at pp. 26–27; CA IOUs, No. 189 at p. 3)
Some stakeholders stated that setting higher standards may result in reduced benefits to consumers. EEI stated that utilities are concerned that if standards are set so high that transformer manufacturers need to use steels with possible supply constraints, there may be negative impacts on the electrical grid, which would have a negative impact on consumers. (EEI, No. 185 at p. 13)
EEI stated that several members expressed concern that the more efficient transformers will be larger in size (height, width, and depth), which will have an impact for all retrofit situations, and they would have much larger weights, which would increase costs in terms of installation and pole structural integrity for retrofits of existing pole-mounted transformers. (EEI, No. 185 at p. 11) A number of electric utilities made similar comments. (BG&E, No. 182 at p. 6;
A number of parties expressed specific concerns about size and space constraints for network/vault transformers. (BG&E, No. 182 at p. 6; ComEd, No. 184 at p. 11; Pepco, No. 145 at pp. 2–3; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12) These concerns lead several parties to recommend a separate equipment class for network/vault transformers. (DOE addresses this issue in section IV.A.2.) EEI and several electric utilities stated that efficiency standards for network/vault transformers should be the same as the efficiency levels that have been in effect since January 1, 2010. (EEI, No. 185 at p. 3; Pepco, No. 145 at p. 2; PE, No. 192 at p. 8; Prolec-GE, No. 177 at p. 12)
Northern Wasco supported the DOE proposal for liquid-immersed units and believed anything beyond would not be cost-effective. (NWC, No. 147 at p. 1) UAW agreed, noting that any level above TSL 1 would not be economically justified. (UAW, No. 194 at p. 2) ATI stated that efficiency levels in excess of the NOPR proposal would create a non-competitive market for new medium-voltage liquid-type designs that would eliminate projected LCC savings. (ATI, No. 54 at p. 2) Steelmakers commented that promulgating energy conservation standards greater than TSL 1 for liquid-immersed transformers would transfer significant competitive power to the sole maker of amorphous metal. (Steelmakers, No. 188 at pp. 9–10)
After the supplementary analysis was presented, which included the new TSLs described in section IV.O.1, a handful of stakeholders recommended that DOE adopt one of the TSLs presented in the supplementary analysis. The Advocates recommended that DOE adopt TSL C, following the supplementary rulemaking process, to increase energy savings relative to the levels proposed in the NOPR and increase life cycle cost savings. (Advocates, No. 235 at p. 2) They added that if DOE wants to foster a more gradual market growth for amorphous metal, TSL D would achieve such an outcome by lowering the standard for pole type transformers, but would still approach the national savings of TSL C. (Advocates, No. 235 at p. 1) Berman Economics agreed that TSL C or D should be selected as they provide the best balance. (Berman Economics, No. 221 at p. 1) NEMA stated that TSL A was the only level presented in the supplementary rulemaking that met the three principles that they applied during the rulemaking process to select levels, but suggested that the level be moved to EL 0 for design line 2. (NEMA, No. 225 at p. 4) Prolec-GE expressed their support for TSL A as well, believing that these efficiency levels provide additional energy savings while preserving manufacturers' ability to use both silicon and amorphous steel to meet the demand of the market. In the absence of TSL A, they recommended TSL 2 as the maximum possible alternative, which they noted would result in higher cost and heavier and larger pole units. (Prolec-GE, No. 238 at p. 3)
The Advocates stated that for LVDT transformers, DOE rejected TSL 3 despite its own economic analysis showing greater net consumer savings, and mean paybacks of five to twelve years, well within a transformer's typical 30-year lifespan. (Advocates, No. 186 at p. 3) They stated that a more thorough investigation of impacts on domestic small manufacturers and a better balancing of public benefits and manufacturer impacts will lead DOE to adopt TSL 3, the maximum level which yields net present value benefits for consumers and can incontrovertibly be achieved using silicon steel cores. They said that if DOE rejects TSL 3, the agency should at least adopt TSL 2, which represents the NEMA Premium® level (30 percent reduction in losses) for all transformers. They added that DOE overestimated the savings from the proposed standards (i.e., TSL 1). (Advocates, No. 186 at pp. 3–4) However, they recommend that if TSL 3 is not adopted, TSL 2 should be chosen, as a number of manufacturers are already committed to manufacturing at NEMA Premium®. (Advocates, No. 186 at p. 7–8) ASAP commented that DOE should select EL 4 for DL7 and DL8. (ASAP, No. 146 at p. 19) EMS stated that low-voltage dry-type standards should be set at TSL 2 or TSL 3. (EMS, No. 178 at p. 7)
CA IOUs stated that TSL 3 is the highest achievable efficiency level at which low-voltage dry-type distribution transformers can be constructed using grain-oriented steel, and they recommend that DOE consider adopting standards at this level. They noted that while DOE expresses concern that small manufacturers are disproportionately impacted by standards for low-voltage dry-type transformers, DOE's analysis shows that there are actually very few small manufacturers in this market, and that those small manufacturers that do exist in the market primarily focus on design lines that are exempted from coverage. (CA IOUs, No. 189 at pp. 2–3)
Schneider Electric and FedPac both expressed support for the low-voltage dry type proposed standards in the NOPR. (FedPac, No. 132 at p. 2; Schneider, No. 180 at p. 1) FedPac noted that the proposed standards may be slightly high for 3-phase above 150 kVA and may put small manufacturers at risk due to potentially large capital investments necessary to remain in business at these levels. (FedPac, No. 132 at pp. 2–3)
Some stakeholders demonstrated support for NEMA Premium® levels for low-voltage dry-type transformers. Eaton noted that NEMA Premium® represents an opportunity to produce efficiency gains and encourage new technologies and recommended adopting NEMA Premium® for DL7 and DL8. (Eaton, No. 157 at p. 2) NEEP pointed out that industry parties suggested higher efficiency on the record during negotiations, including NEMA Premium®. (NEEP, No. 193 at p. 5)
NEMA recommended that DOE select ELs 0, 2 and 2 for DLs 6, 7 and 8, respectively. NEMA noted that NEMA Premium® was still in development. (NEMA, No. 170 at p. 5) NEMA expressed concern that high efficiency standards for LVDT transformers would hurt small U.S. manufacturers. (NEMA, No. 170 at p. 5)
The Advocates expressed support for the proposed standards for medium-voltage dry-type (MVDT) transformers. (The Advocates, No. 186 at p. 2) FedPac noted that the DOE was correct in its NOPR decision to not increase standards for single-phase MVDTs. (FedPac, No. 132 at p. 2)
NEMA made specific recommendations for medium-voltage, dry type transformers. First, it recommended for DL13 that the efficiency level allow for 10 percent more loss that DL12, as these are high BIL transformers. Second, it noted that for single-phase transformers the single-phase efficiency should be less than the three-phase efficiency by a maximum of 30 percent higher losses and should not exceed 2010 standard. (NEMA, No. 170 at p. 4)
NEMA stated that for medium-voltage dry-type transformers used in high-rise buildings, it recommended different treatment because of size and weight
DOE acknowledges the comments described above and has taken them into account in developing today's final rule. As stated previously, DOE seeks to set the highest energy conservation standards that are technologically feasible, economically justified, and that will result in significant energy savings. In section V.C, DOE explains why it has adopted the standards established by this final rule, and it addresses the issues raised in the preceding comments. DOE agrees with many of the concerns associated with higher efficiency transformers, and these considerations contributed to the selection of today's standards. In particular, DOE believes that the increase in medium-voltage dry-type distribution transformer size and weight for the efficiency levels in today's final rule, which were unanimously agreed to by the negotiation committee, will not adversely impact the continued installation and replacement of these transformers.
Table V.1 through Table V.3 present the TSLs analyzed and the corresponding efficiency level for the representative unit in each transformer design line. The mapping of TSLs to corresponding efficiency levels for each design line is described in detail in chapter 10, section 10.2.2.3 of the final rule TSD. The baseline in the tables is equal to the current energy conservation standards.
For liquid-immersed distribution transformers, the efficiency levels in each TSL can be characterized as follows: TSL 1 represents an increase in efficiency where a diversity of electrical steels are cost-competitive and economically feasible for all design lines; TSL 2 represents EL1 for all design lines; TSL 3 represents the maximum efficiency level achievable with M3 core steel; TSL 4 represents the maximum NPV with 7 percent discounting; TSL 5 represents EL 3 for all design lines; TSL 6 represents the maximum source energy savings with positive NPV with 7 percent discounting; and TSL 7 represents the maximum technologically feasible level (max tech).
For low-voltage dry-type distribution transformers, the efficiency levels in each TSL can be characterized as follows: TSL 1 represents the maximum efficiency level achievable with M6 core steel; TSL 2 represents EL 3 for design line 7, EL 2 for design line 8 and no efficiency increase for design line 6; TSL 3 represents the maximum EL achievable using butt-lap miter core manufacturing for single-phase distribution transformers, and full miter core manufacturing for three-phase distribution transformers; TSL 4 represents the maximum NPV with 7 percent discounting; TSL 5 represents the maximum source energy savings with positive NPV with 7 percent discounting; and TSL 6 represents the maximum technologically feasible level (max tech).
For medium-voltage dry-type distribution transformers based on the subcommittee consensus detailed in section II.B.2, above, the efficiency levels in each TSL can be characterized as follows: TSL 1 represents EL1 for all design lines; TSL 2 represents an increase in efficiency where a diversity of electrical steels are cost-competitive and economically feasible for all design lines; TSL 3 represents the maximum NPV with 7 percent discounting; TSL 4 represents the maximum source energy savings with positive NPV with 7 percent discounting; and TSL 5 represents the maximum technologically feasible level (max tech).
To evaluate the net economic impact of standards on transformer customers, DOE conducted LCC and PBP analyses for each TSL. In general, higher-efficiency equipment would affect customers in two ways: (1) Annual operating expense would decrease, and (2) purchase price would increase. Section IV.F.2 of this preamble discusses the inputs DOE used for calculating the LCC and PBP. The LCC and PBP results are calculated from transformer cost and efficiency data that are modeled in the engineering analysis (section IV.C). During the negotiated rulemaking, DOE presented separate transformer cost data based on 2010 and 2011 material prices to the committee members. DOE conducted its LCC and PBP analysis utilizing both the 2010 and 2011 material price cost data. The average results of these two analyses are presented here.
For each design line, the key outputs of the LCC analysis are a mean LCC savings and a median PBP relative to the base case, as well as the fraction of customers for which the LCC will decrease (net benefit), increase (net cost), or exhibit no change (no impact) relative to the base-case product forecast. No impacts occur when the base-case equals or exceeds the efficiency at a given TSL. Table V.4 through Table V.17 show the key results for each transformer design line.
In the customer subgroup analysis, DOE estimated the LCC impacts of the distribution transformer TSLs on purchasers of vault-installed transformers (primarily urban utilities). DOE included only the three-phase liquid-immersed design lines in this analysis, since those types account for the vast majority of vault-installed transformers. Table V.18 shows the mean LCC savings at each TSL for this customer subgroup.
Chapter 11 of the final rule TSD explains DOE's method for conducting the customer subgroup analysis and presents the detailed results of that analysis.
As discussed in section IV.F.3.j, EPCA establishes a rebuttable presumption that an energy conservation standard is economically justified if the increased purchase cost for equipment that meets the standard is less than three times the value of the first-year energy savings resulting from the standard. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) DOE calculated a rebuttable-presumption PBP for each TSL to determine whether DOE could presume that a standard at that level is economically justified. As required by EPCA, DOE based the calculations on the assumptions in the DOE test procedure for distribution transformers. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) As a result, DOE calculated a single rebuttable-presumption payback value, and not a distribution of PBPs, for each TSL. Table V.19 and Table V.21 show the rebuttable-presumption PBPs for the considered TSLs. The rebuttable presumption is fulfilled in those cases where the PBP is three years or less. However, DOE routinely conducts an economic analysis that considers the full range of impacts to the customer, manufacturer, Nation, and environment, as required under 42 U.S.C. 6295(o)(2)(B)(i). The results of that analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level (thereby supporting or rebutting the results of any three-year PBP analysis). Section V.C addresses how DOE considered the range of impacts to select today's standard.
For the MIA in the February 2012 NOPR, DOE used changes in INPV to compare the direct financial impacts of different TSLs on manufacturers (77 FR 7282, February 10, 2012). DOE used the GRIM to compare the INPV of the base case (no new or amended energy conservation standards) to that of each TSL. The INPV is the sum of all net cash flows discounted by the industry's cost of capital (discount rate) to the base year. The difference in INPV between the base case and the standards case is an estimate of the economic impacts that implementing that standard level would have on the distribution transformer industry. For today's final rule, DOE continues to use the methodology presented in the NOPR at 77 FR 7282 (February 10, 2012).
The tables below depict the financial impacts (represented by changes in INPV) of amended energy standards on manufacturers as well as the conversion costs that DOE estimates manufacturers would incur at each TSL. The effect of amended standards on INPV was analyzed separately for each type of distribution transformer manufacturer: liquid-immersed, medium-voltage dry-type, and low-voltage dry-type. To evaluate the range of cash flow impacts on the distribution transformer industry, DOE modeled two different scenarios using different assumptions for markups that correspond to the range of anticipated market responses to new and amended standards. These assumptions correspond to the bounds of a range of market responses that DOE anticipates could occur in the standards case (i.e., where new and amended energy conservation standards apply). Each of the two scenarios results in a
The MIA results for liquid-immersed distribution transformers are as follows:
At TSL 1, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$48.2 million to −$23.5 million, corresponding to a change in INPV of −8.4 percent to −4.1 percent. At this level, industry free cash flow is estimated to decrease by approximately 54.4 percent to $16.4 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
While TSL 1 can be met with traditional steels, including M3, in all design lines, amorphous core transformers will be incrementally more competitive on a first cost basis. According to manufacturer interviews, this would likely induce some manufacturers to gradually build amorphous steel transformer production capacity. Because the production process for amorphous cores is entirely separate from that of silicon steel cores, large investments in new capital, including new core cutting equipment and annealing ovens will be required. Additionally, a great deal of testing, prototyping, design and manufacturing engineering resources will be required because most manufacturers have relatively little experience, if any, with amorphous steel transformers. These capital and production conversion expenses lead to a reduction in cash flow in the years preceding the standard. In the lower-bound scenario, DOE assumes manufacturers can only maintain annual operating profit in the standards case. Therefore, these conversion investments, and manufacturers' higher working capital needs associated with more expensive transformers, drain cash flow and lead to a greater reduction in INPV, when compared to the upper-bound scenario. In the upper bound scenario, DOE assumes manufacturers will be able to fully markup and pass on the higher product costs, leading to higher operating income. This higher operating income essentially offsets the conversion costs and the increase in working capital requirements, leading to a negligible change in INPV at TSL1 in the upper-bound scenario.
At TSL 2, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$109.3 million to −$67.0 million, corresponding to a change in INPV of −19.0 percent to −11.7 percent. At this level, industry free cash flow is estimated to decrease by approximately 133.7 percent to −$12.1 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
TSL 2 requires the same efficiency levels as TSL 1, except for DL 2, which is increased from baseline to EL1. EL1, as opposed to the baseline efficiency, could induce manufacturers to build more amorphous capacity, when compared to TSL 1, because amorphous core transformers become incrementally more cost competitive. Because DL2 represents the largest share of core steel usage of all design lines, this has a significant impact on investments. There are more severe impacts on industry in the lower-bound profitability scenario when these greater one-time cash outlays are coupled with slight margin pressure. In the high-profitability scenario, manufacturers are able to maintain gross margins, mitigating the adverse cash flow impacts of the increased investment in working capital (associated with more expensive transformers).
At TSL 3, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$113.4 million to −$68.9 million, corresponding to a change in INPV of −19.7 percent to −12.0 percent. At this level, industry free cash flow is estimated to decrease by approximately 137.6 percent to −$13.6 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
TSL 3 results are similar to TSL 2 results because the efficiency levels are the same except for DL3 and DL5, which each increase to EL 2 under TSL 3. The increase in stringency makes amorphous
At TSL 4, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$186.1 million to −$97.3 million, corresponding to a change in INPV of −32.4 percent to −16.9 percent. At this level, industry free cash flow is estimated to decrease by approximately 206.6 percent to −$38.4 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
During interviews, manufacturers expressed differing views on whether the efficiency levels embodied in TSL 4 would shift the market away from silicon steels entirely. Because DL3 and DL5 must meet EL4 at this TSL, DOE expects the majority of the market would shift to amorphous core transformers at TSL 4 and above. Even assuming a sufficient supply of amorphous steel were available, TSL 4 and above would require a dramatic build up in amorphous core transformer production capacity. DOE believes this wholesale transition away from silicon steels could seriously disrupt the market, drive small businesses to either source their cores or exit the market, and lead even large businesses to consider moving production offshore or exiting the market altogether. The negative impacts are again driven by the large conversion costs associated with new amorphous steel production lines. If the higher first costs at TSL 4 drive more utilities to refurbish rather than replace failed transformers, a scenario many manufacturers predicted at the efficiency levels and prices embodied in TSL 4, reduced transformer sales could cause further declines in INPV.
At TSL 5, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$193.0 million to −$101.4 million, or a change in INPV of −33.6 percent to −17.6 percent. At this level, industry free cash flow is estimated to decrease by approximately 210.8 percent to −$39.9 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
TSL 5 would likely shift the entire market to amorphous core transformers, leading to even greater investment needs than TSL 4, and further driving the adverse impacts discussed above.
At TSL 6, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$216.7 million to −$88.5 million, corresponding to a change in INPV of −37.7 percent to −15.4 percent. At this level, industry free cash flow is estimated to decrease by approximately 217.5 percent to −$42.3 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that slightly more amorphous core production capacity will be needed because TSL 6-compliant transformers will have somewhat heavier cores and thus require more amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to TSL 5.
At TSL 7, DOE estimates impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$393.5 million to $0.5 million, corresponding to a change in INPV of −68.4 percent to 0.1 percent. At this level, industry free cash flow is estimated to decrease by approximately 246.2 percent to −$52.7 million, compared to the base-case value of $36.0 million in the year before the compliance date (2015).
The impacts at TSL 7 are similar to those DOE expects at TSL 6, except that slightly more amorphous core production capacity will be needed because TSL 7-compliant transformers will have somewhat heavier cores and thus require more amorphous steel. This leads to slightly greater capital expenditures at TSL 7 compared to TSL 6, incrementally reducing industry value.
The MIA results for low-voltage dry-type distribution transformers are as follows:
At TSL 1, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$8.0 million to $14.8 million, corresponding to a change in INPV of −3.4 percent to 6.2 percent. At this level, industry free cash flow is estimated to decrease by approximately 5.0 percent to $14.5 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
TSL 1 provides many design paths for manufacturers to comply. DOE's engineering analysis indicates manufacturers can continue to use the low-capital butt-lap core designs, meaning investment in mitering or wound core capability is not necessary. Manufacturers can use higher-quality grain oriented steels in butt-lap designs to meet TSL1, source some or all cores, or invest in modified mitering capability (if they do not already have it).
At TSL 2, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$11.1 million to $11.8 million, corresponding to a change in INPV of −4.7 percent to 5.0 percent. At this level, industry free cash flow is estimated to decrease by approximately 9.1 percent to $13.8 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
TSL 2 differs from TSL1 in that DL7 must meet EL3, up from EL2. Comments received from the NOPR and consultations with technical experts suggest that butt-lap technology can still be used to achieve EL 3 for DL 7. However, DOE expects the high volume manufacturers which supply most of the market to employ mitered cores at this efficiency level. Therefore, the increase in conversion costs for DL 7, which represents more than three-quarters of the market by core weight in this superclass, is primarily driven by the need to purchase additional core cutting equipment to accommodate the production of larger, mitered cores. Furthermore, manufacturers also indicated that there would be a reduced burden at TSL 2 relative to TSL 1 because they would be able to standardize the use of NEMA Premium® (with the exception of DL 6).
At TSL 3, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$18.6 to $28.1 million, corresponding to a change in INPV of −7.8 percent to 11.8 percent. At this level, industry free cash flow is estimated to decrease by approximately 31.9 percent to $10.4 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
TSL3 represents EL4 for DL6, DL7, and DL8. Although manufacturers may be able to meet EL4 using M4 steel, comments and interviews suggest uncertainty about the ability of M4 to meet EL 4 for all design lines. Manufacturers may be forced to use higher-grade and thinner steels like M3, H1, and H0. However, these thinner steels, in combination with larger cores, will dramatically slow production throughput and therefore require the industry to expand capacity to maintain current shipments. This is the reason for the increase in conversion costs. In the lower-bound profitability scenario, when DOE assumes the industry cannot fully pass on incremental costs, these investments and the higher working capital needs drain cash flow and lead to the negative impacts shown in the preservation of operating profit scenario. In the high-profitability scenario, impacts are slightly positive because DOE assumes manufacturers are able to fully recoup their conversion expenditures through higher operating cash flow.
At TSL 4, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$38.9 million to $42.3 million, corresponding to a change in INPV of −16.4 percent to 17.8 percent. At this level, industry free cash flow is estimated to decrease by approximately 87.2 percent to $1.9 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
TSL 4 and higher would create significant challenges for the industry and likely disrupt the marketplace. DOE's conversion costs at TSL 4 assume the industry will entirely convert to amorphous wound core technology to meet the efficiency standards. Few manufacturers of distribution transformers in this superclass have any experience with amorphous steel or wound core technology and would face a steep learning curve. This is reflected in the large conversion costs and adverse impacts on INPV in the Preservation of Operating Profit scenario. Most manufacturers DOE interviewed expected many low-volume manufacturers to exit the DOE-covered market altogether if amorphous steel was required to meet the standard. As such, DOE believes TSL 4 could lead to greater consolidation than the industry would experience at lower TSLs.
At TSL 5, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$46.8 million to $61.0 million, corresponding to a change in INPV of −19.7 percent to 25.7 percent. At this level, industry free cash flow is estimated to decrease by approximately 93.9 percent to $0.9 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
The impacts at TSL 5 are similar to those DOE expects at TSL 4, except that slightly more amorphous core production capacity will be needed because TSL 5-compliant transformers will have somewhat heavier cores and thus require more amorphous steel. This leads to slightly greater capital expenditures at TSL 5 compared to TSL 4.
At TSL 6, DOE estimates impacts on INPV for low-voltage dry-type distribution transformer manufacturers to range from −$78.6 million to $118.9 million, corresponding to a change in INPV of −33.1 percent to 50.1 percent. At this level, industry free cash flow is estimated to decrease by approximately 138 percent to −$5.8 million, compared to the base-case value of $15.2 million in the year before the compliance date (2015).
The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that slightly more amorphous core production capacity will be needed because TSL 6-compliant transformers will have somewhat heavier cores and thus require more amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to TSL 5.
The MIA results for medium-voltage dry-type distribution transformers are as follows:
At TSL 1, DOE estimates impacts on INPV for medium-voltage dry-type distribution transformer manufacturers to range from −$1.4 million to $0.7 million, corresponding to a change in INPV of −2.0 percent to 1.0 percent. At this level, industry free cash flow is estimated to decrease by approximately 2.3 percent to $4.3 million, compared to the base-case value of $4.4 million in the year before the compliance date (2015).
TSL 1 represents EL1 for all MVDT design lines. For DL12, the largest design line by core steel usage, manufacturers have a variety of steels available to them, including M4, the most common steel in the superclass. Additionally, the vast majority of the market already uses step-lap mitering technology. Therefore, DOE anticipates only moderate conversion costs for the industry, mainly associated with slower throughput due to larger cores. Some manufacturers may need to slightly expand capacity to maintain throughput and/or modify equipment to manufacturer with greater precision and tighter tolerances. In general, however, conversion expenditures should be relatively minor compared to INPV. For this reason, TSL 1 yields relatively minor adverse changes to INPV in the standards case.
At TSL 2 (the consensus recommendation from the negotiating committee), DOE estimates impacts on INPV for medium-voltage dry-type distribution transformer manufacturers to range from −$2.9 million to $3.0 million, corresponding to a change in INPV of −4.2 percent to 4.4 percent. At this level, industry free cash flow is estimated to decrease by approximately 6.0 percent to $4.2 million, compared to the base-case value of $4.4 million in the year before the compliance date (2015).
Compared to TSL 1, TSL 2 requires EL2, rather than EL1, in DLs 10, 12, and 13B. Because M4 (as well as the commonly used H1) can still be employed to meet these levels, DOE expects similar results at TSL 2 as at TSL 1. Slightly greater conversion costs will be required as the compliant transformers will have heavier cores, all other things being equal, meaning additional capacity may be necessary depending on each manufacturer's current capacity utilization rate. As with TSL 1, TSL 2 will not require significant changes to most manufacturers production processes because the thickness of the steels will not change significantly, if at all.
At TSL 3, DOE estimates impacts on INPV for medium-voltage dry-type distribution transformer manufacturers to range from −$10.7 million to $5.7 million, corresponding to a change in INPV of −15.6 percent to 8.3 percent. At this level, industry free cash flow is estimated to decrease by approximately 53.4 to $2.1 million, compared to the base-case value of $4.4 million in the year before the compliance date (2015).
At TSL 4, DOE estimates impacts on INPV for medium-voltage dry-type distribution transformer manufacturers to range from−$10.7 million to $5.6 million, corresponding to a change in INPV of −15.5 percent to 8.2 percent. At this level, industry free cash flow is estimated to decrease by approximately −53.4 percent to $2.1 million, compared to the base-case value of $4.4 million in the year before the compliance date (2015).
TSL 3 and TSL 4 require EL2 for DL9 and DL10, but EL4 for DL11 through DL13B, which hold the majority of the volume. Several manufacturers were concerned TSL 3 would require some of the high volume design lines to use H1 or H0, or transition entirely to amorphous wound cores (with which the industry has experience). Without a cost effective M-grade steel option, the industry could face severe disruption. Even assuming a sufficient supply of Hi-B steel, which is generally used and priced for the power transformer market, relatively large expenditures would be required in R&D and engineering as most manufacturers would have to move production to steel with which they have little experience. DOE estimates total conversion costs would more than double at TSL 3, relative to TSL 2. If, based on the movement of steel prices, EL4 can be met cost competitively only through the use of amorphous steel or an exotic design with little or no current place in scale manufacturing, manufacturers
At TSL 5, DOE estimates impacts on INPV for medium-voltage dry-type distribution transformer manufacturers to range from −$34.1 million to $12.9 million, corresponding to a change in INPV of −49.7 percent to 18.7 percent. At this level, industry free cash flow is estimated to decrease by approximately 189.1 percent to −$3.9 million, compared to the base-case value of $4.4 million in the year before the compliance date (2015).
TSL 5 represents max-tech and yields results similar to but more severe than TSL 4 results. The engineering analysis shows that the entire market must convert to amorphous wound cores at TSL 5. Because the industry has no experience with wound core technology, and little, if any, experience with amorphous steel, this transition would represent a tremendous challenge for industry. Interviews suggest most manufacturers would exit the market rather altogether or source their cores rather than make the investments in plant, equipment, and the R&D required to meet such levels.
Liquid-Immersed. Based on interviews with manufacturers and other industry research, DOE estimates that there are roughly 5,000 employees associated with DOE-covered liquid-immersed distribution transformer production and some three-quarters of these workers are located domestically. DOE does not expect large changes in domestic employment to occur due to today's standard. Manufacturers generally agreed that amorphous core steel production is more labor-intensive and would require greater labor expenditures than tradition steel core production. So long as domestic plants are not relocated outside the country, DOE expects moderate increases in domestic employment at TSL1 and TSL2. There could be a small drop in employment at small, domestic manufacturing firms if small manufacturers began sourcing cores. This employment would presumably transfer to the core makers, some of whom are domestic and some of whom are foreign. There is a risk that higher energy conservation standards that largely require the use of amorphous steel could cause even large manufacturers who are currently producing transformers in the U.S. to evaluate offshore options. Faced with the prospect of wholesale changes to their production process, large investments and stranded assets, some manufacturers expect to strongly consider shifting production offshore at TSL 3 due to the increased labor expenses associated with the production processes required to make amorphous steel cores. In summary, at TSLs 1 and 2, DOE does not expect significant impacts on employment, but at TSL 3 or greater, which would require more investment, the impact is very uncertain.
Low-Voltage Dry-Type. Based on interviews with manufacturers, DOE estimates that there are approximately 2,200 employees associated with DOE-covered LVDT production. Approximately 75 percent of these employees are located outside of the U.S. Typically, high volume units are made in Mexico, taking advantage of lower labor rates, while custom designs are made closer to the manufacturer's customer base or R&D centers. DOE does not expect large changes in domestic employment to occur due to today's standard. Most production already occurs outside the U.S. and, by and large, manufacturers agreed that most design changes necessary to meet higher energy conservation standards would increase labor expenditures, not decrease them. If, however, small manufacturers began sourcing cores instead of manufacturing them in-house, there could be a small drop in employment at these firms. This employment would presumably transfer to the core makers, some of whom are domestic and some of whom are foreign. In summary, DOE does not expect significant changes to domestic LVDT industry employment levels as a result of today's standards. Higher TSLs may lead to small declines in domestic employment as more firms will be challenged with what amounts to clean-sheet redesigns. Facing the prospect of green field investments, these manufacturers may elect to make those investments in lower-labor cost countries.
Medium-Voltage Dry-Type. Based on interviews with manufacturers, DOE estimates that there are approximately 1,850 employees associated with DOE-covered MVDT production. Approximately 75 percent of these employees are located domestically. With the exception of TSLs that require amorphous cores, manufacturers agreed that most design changes necessary to meet higher standards would increase labor expenditures, not decrease them, but current production equipment would not be stranded, mitigating the incentive to move production offshore. Corroborating this, the largest manufacturer and domestic employer in this market has indicated that the standard in this final rule, will not cause their company to reconsider production location. As such, DOE does not expect significant changes to domestic MVDT industry employment levels as a result of the standard in today's final rule. For TSLs that would require amorphous cores, DOE does anticipate significant changes to domestic MVDT industry employment levels.
Based on manufacturer interviews, DOE believes that there is significant excess capacity in the distribution transformer market. Shipments in the industry are well down from their peak in 2007, according to manufacturers. Therefore, DOE does not believe there would be any production capacity constraints at TSLs that do not require dramatic transitions to amorphous cores. For those TSLs that require amorphous cores in significant volumes, DOE believes there is potential for capacity constraints in the near term due to limitations on core steel availability. However, for the levels in today's rule, DOE does not foresee any capacity constraints.
Small manufacturers, niche equipment manufacturers, and manufacturers exhibiting a cost structure substantially different from the industry average could be affected disproportionately. Therefore, using average cost assumptions to develop an industry cash-flow estimate is inadequate to assess differential impacts among manufacturer subgroups. DOE considered small manufacturers as a subgroup in the MIA. For a discussion of the impacts on the small manufacturer subgroup, see the Regulatory Flexibility Analysis in section VI.B and chapter 12 of the final rule TSD.
While any one regulation may not impose a significant burden on manufacturers, the combined effects of recent or impending regulations may have serious consequences for some manufacturers, groups of manufacturers, or an entire industry. Assessing the impact of a single regulation may overlook this cumulative regulatory
For each TSL, DOE projected energy savings for transformers purchased in the 30-year period that begins in the year of compliance with amended standards (2016–2045). The savings are measured over the entire lifetime of products purchased in the 30-year period, which in the case of transformers extends through 2105. DOE quantified the energy savings attributable to each TSL as the difference in energy consumption between each standards case and the base case. Table V.28 presents the estimated energy savings for each considered TSL. The approach used is further described in section IV.G.
For this rulemaking, DOE undertook a sensitivity analysis using nine rather than 30 years of product shipments. The choice of a nine-year period is a proxy for the timeline in EPCA for the review of the energy conservation standard established in this final rule and potential revision of and compliance with a new standard for distribution transformers.
DOE estimated the cumulative NPV of the total costs and savings for customers that would result from the TSLs considered for distribution transformers. In accordance with OMB's guidelines on regulatory analysis,
Table V.30 shows the customer NPV results for each TSL considered. In each case, the impacts cover the lifetime of equipment purchased in 2016–2045.
The results shown in the table reflect the default equipment price trend, which uses constant prices. DOE conducted an NPV sensitivity analysis using alternative price trends. DOE developed one forecast in which prices decline after 2010, and one in which prices rise. The NPV results from the associated sensitivity cases are described in appendix 10–C of the final rule TSD.
The NPV results based on the aforementioned nine-year analytical period are presented in Table V.31. The impacts are counted over the lifetime of equipment purchased in 2016–2024. As mentioned previously, this information is presented for informational purposes only and is not indicative of any change in DOE's analytical methodology or decision criteria.
DOE expects energy conservation standards for distribution transformers to reduce energy costs for equipment owners, and the resulting net savings to be redirected to other forms of economic activity. Those shifts in spending and economic activity could affect the demand for labor. As described in section IV.J, DOE used an input/output model of the U.S. economy to estimate indirect employment impacts of the TSLs that DOE considered in this rulemaking. DOE understands that there are uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Therefore, DOE generated results for near-term time frames (2016–2020), where these uncertainties are reduced.
The results suggest that today's standards are likely to have negligible impact on the net demand for labor in the economy. The net change in jobs is so small that it would be imperceptible in national labor statistics and might be offset by other, unanticipated effects on employment. Chapter 13 of the final rule TSD presents detailed results.
DOE believes that the standards in today's rule will not lessen the utility or performance of distribution transformers.
DOE has also considered any lessening of competition that is likely to result from new and amended standards. The Attorney General determines the impact, if any, of any lessening of competition likely to result from a proposed standard, and transmits such determination to the Secretary of Energy, together with an analysis of the nature and extent of such impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))
To assist the Attorney General in making such a determination, DOE has provided the Department of Justice (DOJ) with copies of this notice and the TSD for review. DOE considered DOJ's comments on the proposed rule in preparing the final rule.
Enhanced energy efficiency, where economically justified, improves the Nation's energy security, strengthens the economy, and reduces the environmental impacts or costs of energy production. Reduced electricity demand due to energy conservation standards is also likely to reduce the cost of maintaining the reliability of the electricity system, particularly during
Energy savings from standards for distribution transformers could also produce environmental benefits in the form of reduced emissions of air pollutants and greenhouse gases associated with electricity production. Table V.32 provides DOE's estimate of cumulative CO
As part of the analysis for this rule, DOE estimated monetary benefits likely to result from the reduced emissions of CO
Table V.33 presents the global value of CO
DOE is well aware that scientific and economic knowledge about the contribution of CO
DOE also estimated a range for the cumulative monetary value of the economic benefits associated with NO
The NPV of the monetized benefits associated with emissions reductions can be viewed as a complement to the NPV of the customer savings calculated for each TSL considered in this rulemaking. Table V.35 through Table V.37 present the NPV values that result from adding the estimates of the potential economic benefits resulting from reduced CO
Although adding the value of customer savings to the values of emission reductions provides a valuable perspective, two issues should be considered. First, the national operating cost savings are domestic U.S. customer monetary savings that occur as a result of market transactions, while the value of CO
The Secretary of Energy, in determining whether a standard is economically justified, may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII))
Electrical steel is a critical consideration in the design and manufacture of distribution transformers, amounting for more than 60 percent of the distribution transformers mass in some designs. Rapid changes in the supply or pricing of certain grades can seriously hinder manufacturers' abilities to meet the market demand and, as a result, this rulemaking has extensively examined the effects of electrical steel supply and availability.
DOE's most important conclusion from this examination is that several energy efficiency levels in each design line are attainable only by using amorphous steel, which is currently produced by only one supplier in any significant volume and that supplier at present does not have enough capacity to supply the industry at all-amorphous standard levels. Several more energy efficiency levels are reachable with the top grades of conventional (grain-oriented) electrical steels, but this would result in distribution transformers that are unlikely to be cost-competitive with the often more-efficient amorphous units. As stated above, switching to amorphous steel is not practicable as there are availability concerns with amorphous steel.
Distribution transformers are also highly customized products. Manufacturers routinely build only one or a handful of units of a particular design and require flexibility with respect to construction materials to remain competitive. Setting a standard that either technologically or economically required amorphous material would both eliminate a large amount of design flexibility and expose the industry to enormous risk with respect to supply and pricing of core steel. For both reasons, DOE considered electrical steel availability to be a significant factor in determining which TSLs were economically justified.
When considering proposed standards, the new or amended energy conservation standard that DOE adopts for any type (or class) of covered equipment shall be designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy determines is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) In determining whether a standard is economically justified, the Secretary must determine whether the benefits of the standard exceed its
For today's rulemaking, DOE considered the impacts of standards at each TSL, beginning with the max-tech level, to determine whether that level was economically justified. Where the max-tech level was not justified, DOE then considered the next most efficient level and undertook the same evaluation until it reached the highest efficiency level that is technologically feasible, economically justified and saves a significant amount of energy.
To aid the reader in understanding the benefits and/or burdens of each TSL, tables in this section summarize the quantitative analytical results for each TSL, based on the assumptions and methodology discussed herein. The efficiency levels contained in each TSL are described in section V.A. In addition to the quantitative results presented in the tables, DOE also considers other burdens and benefits that affect economic justification. These include the impacts on identifiable subgroups of customers who may be disproportionately affected by a national standard, and impacts on employment. Section V.B.1 presents the estimated impacts of each TSL for the considered subgroup. DOE discusses the impacts on employment in transformer manufacturing in section V.B.2.b, and discusses the indirect employment impacts in section V.B.3.c.
Table V.38 and Table V.39 summarize the quantitative impacts estimated for each TSL for liquid-immersed distribution transformers.
First, DOE considered TSL 7, the most efficient level (max tech), which would save an estimated total of 7.01 quads of energy, an amount DOE considers significant. TSL 7 has an estimated NPV of customer benefit of −$12.97 billion using a 7 percent discount rate, and −$8.50 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 7 are 501.0 million metric tons of CO
At TSL 7, the average LCC impact ranges from −$579 for design line 2 to $4,619 for design line 5. The median PBP ranges from 31.6 years for design line 2 to 10.2 years for design line 4. The share of customers experiencing a net LCC benefit ranges from 32.8 percent for design line 2 to 70.1 percent for design line 3.
At TSL 7, the projected change in INPV ranges from a decrease of $394 million to an increase of $0.5 million. If the decrease of $394 million were to occur, TSL 7 could result in a net loss of 68.4 percent in INPV to manufacturers of liquid-immersed distribution transformers. At TSL 7, there is a risk of very large negative impacts on manufacturers due to the substantial capital and engineering costs they would incur and the market disruption associated with the likely transition to a market entirely served by amorphous steel. Additionally, if manufacturers' concerns about their customers rebuilding rather than replacing transformers at the price points projected for TSL 7 are realized, new transformer sales would suffer and make it even more difficult to recoup investments in amorphous transformer production capacity. DOE also has concerns about the competitive impact of TSL 7 on the electrical steel industry, as only one proven supplier of amorphous ribbon currently serves the U.S. market.
In view of the foregoing, DOE concludes that, at TSL 7 for liquid-immersed distribution transformers, the benefits of energy savings, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the potential multi-billion dollar negative net economic cost, the economic burden on customers as indicated by large PBPs, significant increases in installed cost, and the large percentage of customers who would experience LCC increases, the capital and engineering costs that could result in a large reduction in INPV for manufacturers, and the risk that manufacturers may not be able to obtain the quantities of amorphous steel required to meet standards at TSL 7. Consequently, DOE has concluded that TSL 7 is not economically justified.
Next, DOE considered TSL 6, which would save an estimated total of 4.09 quads of energy, an amount DOE considers significant. TSL 6 has an estimated NPV of customer benefit of $0.74 billion using a 7 percent discount rate, and $10.27 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 6 are 321.8 million metric tons of CO
At TSL 6, the average LCC impact ranges from $311 for design line 2 to $12,014 for design line 5. The median PBP ranges from 5.6 years for design line 4 to 15.5 years for design line 2. The share of customers experiencing a net LCC benefit ranges from 82.2 percent for design line 2 to 96.9 percent for design line 4.
At TSL 6, the projected change in INPV ranges from a decrease of $217 million to a decrease of $89 million. If the decrease of $217 million were to occur, TSL 6 could result in a net loss of 37.7 percent in INPV to manufacturers of liquid-immersed distribution transformers. At TSL 6, DOE recognizes the risk of very large negative impacts on manufacturers due to the large capital and engineering costs and the market disruption associated with the likely transition to a market entirely served by amorphous steel. Additionally, if manufacturers' concerns about their customers rebuilding rather than replacing their transformers at the price points projected for TSL 6 are realized, new transformer sales would suffer and make it even more difficult to recoup investments in amorphous transformer production capacity.
The energy savings under TSL 6 are achievable only by using amorphous steel, which only one supplier currently produces in any significant volume (annual production capacity of approximately 100,000 tons, the vast majority of which serves global demand). Thus, the current availability is far below the amount that would be required to meet the U.S. liquid-immersed transformer market demand of approximately 250,000 tons. Electrical steel is a critical consideration in the manufacture of distribution transformers, accounting for more than 60 percent of the transformer's mass in some designs. DOE is concerned that the current supplier, together with others that might enter the market, would not be able to increase production of amorphous steel rapidly enough to supply the amounts that would be needed by transformer manufacturers before 2015. Therefore, setting a standard that requires amorphous material would expose the industry to enormous risk with respect to core steel supply. DOE also has concerns about the competitive impact of TSL 6 on the electrical steel industry. TSL 6 could jeopardize the ability of silicon steels to compete with amorphous metal, which risks upsetting competitive balance among steel suppliers and between them and their customers.
In view of the foregoing, DOE concludes that, at TSL 6 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 5, which would save an estimated total of 3.30 quads of energy, an amount DOE considers significant. TSL 5 has an estimated NPV of customer benefit of $1.60 billion using a 7 percent discount rate, and $10.19 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 5 are 273.4 million metric tons of CO
At TSL 5, the average LCC impact ranges from $330 for design line 2 to$8,616 for design line 5. The median PBP ranges from 5.6 years for design line 4 to 13.0 years for design line 2. The share of customers experiencing a net LCC benefit ranges from 85.2 percent for design line 5 to 96.9 percent for design line 4.
At TSL 5, the projected change in INPV ranges from a decrease of $193 million to a decrease of $101 million. If the decrease of $193 million were to occur, TSL 5 could result in a net loss of 33.6 percent in INPV to manufacturers of liquid-immersed distribution transformers. At TSL 5, DOE recognizes the risk of very large negative impacts on manufacturers due to the large capital and engineering costs they would incur and the market disruption associated with the likely transition to a market almost entirely served by amorphous steel. Additionally, if manufacturers' concerns about their customers rebuilding rather than replacing transformers at the price points projected for TSL 5 are realized, new transformer sales would suffer and make it even more difficult to recoup investments in amorphous core transformer production capacity.
Similar to TSL 6 as described above, the energy savings under TSL 5 are achievable only by using amorphous steel, which is currently available from only one supplier with significant volume and that supplier's production capacity of 100,000 tons is far below what would be required to meet market demand for electrical steel. DOE is concerned that the current supplier, together with others that might enter the market, would not be able to increase production of amorphous steel rapidly enough to supply the amounts that would be needed by transformer manufacturers before 2015. Therefore, setting a standard that requires amorphous material would expose the industry to enormous risk with respect to core steel supply. TSL 5 could jeopardize the ability of silicon steels to compete with amorphous metal, which risks upsetting competitive balance among steel suppliers and between them and their customers.
In view of the foregoing, DOE concludes that, at TSL 5 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 4, which would save an estimated total of 3.31 quads of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of customer benefit of $1.92 billion using a 7 percent discount rate, and $10.78 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 4 are 274.6 million metric tons of CO
At TSL 4, the average LCC impact ranges from $343 for design line 2 to $10,382 for design line 5. The median PBP ranges from 11.1 years for design line 2 to 6.5 years for design line 3. The share of customers experiencing a net LCC benefit ranges from 88.6 percent for design line 2 to 95.9 percent for design line 4.
At TSL 4, the projected change in INPV ranges from a decrease of $186 million to a decrease of $97 million. If the decrease of $186 million were to occur, TSL 4 could result in a net loss of 32.4 percent in INPV to manufacturers of liquid-immersed distribution transformers. At TSL 4, DOE recognizes the risk of large negative impacts on manufacturers due to the substantial capital and engineering costs they would incur. Additionally, if manufacturers' concerns about their customers rebuilding rather than replacing transformers at the price points projected for TSL 4 are realized, new transformer sales would suffer and make it even more difficult to recoup investments in amorphous core transformer production capacity.
DOE is also concerned that TSL 4, like the higher TSLs, will require amorphous steel to be competitive in many applications and at least a few design lines. As stated previously, the available supply of amorphous steel is well below the amount that would likely be required to meet the U.S. liquid-immersed distribution transformer market demand. DOE is concerned that the current supplier, together with others that might enter the market, would not be able to increase production of amorphous steel rapidly enough to supply the amounts that would be needed by transformer manufacturers before 2015. Therefore, setting a standard that requires amorphous material would expose the industry to enormous risk with respect to core steel supply.
In addition, depending on how steel prices react to a standard, DOE believes TSL 4 could threaten the viability of a place in the market for conventional steel. Therefore, as with higher TSLs, DOE has concerns about the competitive impact of TSL 4 on the electrical steel manufacturing industry.
In view of the foregoing, DOE concludes that, at TSL 4 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 3, which would save an estimated total of 1.76 quads of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of customer benefit of $0.91 billion using a 7 percent discount rate, and $6.62 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 3 are 156.5 million metric tons of CO
At TSL 3, the average LCC impact ranges from $153 for design line 1 to $6,852 for design line 5. The median PBP ranges from 24.7 years for design line 1 to 5.8 years for design line 3. The share of customers experiencing a net LCC benefit ranges from 55.6 percent for design line 1 to 92.8 percent for design line 4.
At TSL 3, the projected change in INPV ranges from a decrease of $113 million to a decrease of $69 million. If the decrease of $113 million were to occur, TSL 3 could result in a net loss of 19.7 percent in INPV to manufacturers. At TSL 3, DOE recognizes the risk of large negative impacts on manufacturers due to the large capital and engineering costs they would incur.
Although the industry can manufacture liquid-immersed distribution transformers at TSL 3 from M3 or lower grade steels, the positive LCC and national impacts results described above are based on lowest first-cost designs, which include amorphous steel for all the design lines analyzed. As is the case with higher TSLs, DOE is concerned that the current supplier, together with others that might enter the market, would not be able to increase production of amorphous steel rapidly enough to supply the amounts that would be needed by transformer manufacturers before 2015. If manufacturers were to meet standards at TSL 3 using M3 or lower grade steels, DOE's analysis shows that the LCC impacts are negative.
In view of the foregoing, DOE concludes that, at TSL 3 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 2, which would save an estimated total of 1.56 quads of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of customer benefit of $0.69 billion using a 7-percent discount rate, and $4.82 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 2 are 143.1 million metric tons of CO
At TSL 2, the average LCC impact ranges from $153 for design line 1 to $3,668 for design line 5. The median PBP ranges from 24.7 years for design line 1 to 6.5 years for design line 5. The share of customers experiencing a net LCC benefit ranges from 55.6 percent for design line 1 to 92.8 percent for design line 4.
At TSL 2, the projected change in INPV ranges from a decrease of $110 million to a decrease of $67 million. If the decrease of $110 million were to occur, TSL 2 could result in a net loss of 19 percent in INPV to manufacturers of liquid-immersed distribution transformers. At TSL 2, DOE recognizes the risk of negative impacts on manufacturers due to the significant capital and engineering costs they would incur.
Although the industry can manufacture liquid-immersed transformers at TSL 2 from M3 or lower grade steels, the positive LCC and national impacts results described above are based on lowest first-cost designs, which include amorphous steel for design line 2. This design line represents approximately 44 percent of all liquid-immersed transformer shipments by MVA. Amorphous steel is currently available in significant volume from one supplier whose annual
In view of the foregoing, DOE concludes that, at TSL 2 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 1, which would save an estimated total of 0.92 quad of energy, an amount DOE considers significant. TSL 1 has an estimated NPV of customer benefit of $0.58 billion using a 7-percent discount rate, and $3.12 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 1 are 82.2 million metric tons of CO
At TSL 1, the average LCC impact ranges from $83 for design line 2 to $3,668 for design line 5. The median PBP ranges from 17.7 years for design line 1 to 5.9 years for design line 2. The share of customers experiencing a net LCC benefit ranges from 55.2 percent for design line 2 to 92.8 percent for design line 4.
At TSL 1, the projected change in INPV ranges from a decrease of $48 million to a decrease of $24 million. If the decrease of $48 million were to occur, TSL 1 could result in a net loss of 8.4 percent in INPV to manufacturers of liquid-immersed distribution transformers.
The energy savings under TSL 1 are achievable without using amorphous steel. Therefore, the aforementioned risks that manufacturers may not be able to obtain the quantities of amorphous steel required to meet standards are not present under TSL 1.
After considering the analysis and weighing the benefits and the burdens, DOE has concluded that at TSL 1 for liquid-immersed distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average customer LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the emissions reductions would outweigh the potential reduction in INPV for manufacturers.
In view of the foregoing, DOE has concluded that TSL 1 would save a significant amount of energy and is technologically feasible and economically justified. For the above considerations, DOE today adopts the energy conservation standards for liquid-immersed distribution transformers at TSL 1. Table V.40 presents the energy conservation standards for liquid-immersed distribution transformers.
Table V.41 and Table V.42 summarize the quantitative impacts estimated for each TSL for low-voltage dry-type distribution transformers.
First, DOE considered TSL 6, the most efficient level (max tech), which would save an estimated total of 4.94 quads of energy, an amount DOE considers significant. TSL 6 has an estimated NPV of customer benefit of −$1.92 billion using a 7-percent discount rate, and $5.17 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 6 are 319.3 million metric tons of CO
At TSL 6, the average LCC impact ranges from −$2,938 for design line 8 to $212 for design line 7. The median PBP ranges from 31.7 years for design line 6 to 16.8 years for design line 7. The share of customers experiencing a net LCC benefit ranges from 3.4 percent for design line 6 to 54.4 percent for design line 7.
At TSL 6, the projected change in INPV ranges from a decrease of $79 million to an increase of $119 million. If the decrease of $79 million occurs, TSL 6 could result in a net loss of 33.1 percent in INPV to manufacturers of low-voltage dry-type distribution transformers. At TSL 6, DOE recognizes the risk of very large negative impacts on the industry. TSL 6 would require manufacturers to scrap nearly all production assets and create transformer designs with which most, if not all, have no experience. DOE is concerned, in particular, about large impacts on small businesses, which may not be able to procure sufficient volume of amorphous steel at competitive prices, if at all.
In view of the foregoing, DOE concludes that, at TSL 6 for low-voltage dry-type distribution transformers, the benefits of energy savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 5, which would save an estimated total of 4.48 quads of energy, an amount DOE considers significant. TSL 5 has an estimated NPV of customer benefit of $2.22 billion using a 7 percent discount rate, and $11.80 billion using a 3 percent discount rate.
The cumulative emissions reductions at TSL 5 are 297.6 million metric tons of CO
At TSL 5, the average LCC impact ranges from −$2,938 for design line 8 to $2,280 for design line 7. The median PBP ranges from 22.5 years for design line 8 to 6.3 years for design line 7. The share of customers experiencing a net LCC benefit ranges from 20.7 percent for design line 8 to 96.7 percent for design line 7.
At TSL 5, the projected change in INPV ranges from a decrease of $47 million to an increase of $61 million. If the decrease of $47 million occurs, TSL 5 could result in a net loss of 19.7 percent in INPV to manufacturers of low-voltage dry-type distribution transformers. At TSL 5, DOE recognizes the risk of very large negative impacts on the industry. TSL 5 would require manufacturers to scrap nearly all production assets and create transformer designs with which most, if not all, have no experience. DOE is concerned, in particular, about large impacts on small businesses, which may not be able to procure sufficient volume of amorphous steel at competitive prices, if at all.
In view of the foregoing, DOE concludes that, at TSL 5 for low-voltage dry-type distribution transformers, the benefits of energy savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 4, which would save an estimated total of 4.39 quads of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of customer benefit of $3.34 billion using a 7-percent discount rate, and $13.65 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 4 are 292.8 million metric tons of CO
At TSL 4, the average LCC impact ranges from $148 for design line 6 to $4,261 for design line 8. The median PBP ranges from 15.7 years for design line 6 to 6.3 years for design line 7. The share of customers experiencing a net LCC benefit ranges from 62.2 percent for design line 6 to 96.7 percent for design line 7.
At TSL 4, the projected change in INPV ranges from a decrease of $39 million to an increase of $42 million. If the decrease of $39 million occurs, TSL 4 could result in a net loss of 16.4 percent in INPV to manufacturers of low-voltage dry-type distribution transformers. At TSL 4, DOE recognizes the risk of very large negative impacts on the industry. As with the higher TSLs, TSL 4 would require manufacturers to scrap nearly all production assets and create transformer designs with which most, if not all, have no experience. DOE is concerned, in particular, about large impacts on small businesses, which may not be able to procure sufficient volume of amorphous steel at competitive prices, if at all.
Additionally, TSL 4 requires significant investment in advanced core construction equipment such are step-lap mitering machines or wound core production lines, as butt lap designs, even with high-grade designs, are unlikely to comply. Given their more limited engineering resources and capital, small businesses may find it difficult to make these designs at competitive prices and may have to exit the market. At the same time, however, those small manufacturers may be able to source their cores—and many are doing so to a significant extent currently—which could mitigate impacts.
In view of the forgoing, DOE concludes that, at TSL 4 for low-voltage dry-type distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 3, which would save an estimated total of 3.05 quads of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of customer benefit of $2.82 billion using a 7-percent discount rate, and $10.38 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3 are 203.0 million metric tons of CO
At TSL 3, the average LCC impact ranges from $325 for design line 6 to $2,724 for design line 8. The median PBP ranges from 12.4 years for design line 6 to 4.1 years for design line 7. The
At TSL 3, the projected change in INPV ranges from a decrease of $19 million to an increase of $28 million. If the decrease of $19 million occurs, TSL 3 could result in a net loss of 7.8 percent in INPV to manufacturers of low-voltage dry-type distribution transformers. At TSL 3, DOE recognizes the risk of negative impacts on the industry, particularly the small manufacturers. While TSL 3 could likely be met with M4 steel, DOE's analysis shows that this design option is at the edge of its technical feasibility at the efficiency levels comprised by TSL 3. Although these levels could be met with M3 or better steels, DOE is concerned that a significant number of small manufacturers would be unable to acquire these steels in sufficient supply and quality to compete.
Additionally, TSL 3 requires significant investment in advanced core construction equipment such are step-lap mitering machines or wound core production lines, as butt lap designs, even with high-grade designs, are unlikely to comply. Given their more limited engineering resources and capital, small businesses may find it difficult to make these designs at competitive prices and may have to exit the market. At the same time, however, those small manufacturers may be able to source their cores—and many are doing so to a significant extent currently—which could mitigate impacts.
In view of the foregoing, DOE concludes that, at TSL 3 for low-voltage dry-type distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive average LCC savings, generating capacity reductions, emission reductions, and the estimated monetary value of the CO
Next, DOE considered TSL 2, which would save an estimated total of 2.43 quads of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of customer benefit of $2.67 billion using a 7-percent discount rate, and $9.04 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 2 are 161.6 million metric tons of CO
At TSL 2, the average LCC impact ranges from $0 for design line 6 to $2,588 for design line 8. The median PBP ranges from 7.7 years for design line 8 to 0 years for design line 6. The share of customers experiencing a net LCC benefit ranges from 0 percent for design line 6 to 98.7 percent for design line 7.
At TSL 2, the projected change in INPV ranges from a decrease of $11 million to an increase of $12 million. If the decrease of $11 million occurs, TSL 2 could result in a net loss of 4.7 percent in INPV to manufacturers of low-voltage dry-type distribution transformers. At TSL 2, manufacturers have the option of continuing to produce transformers using butt-lap technology, investing in mitering equipment, or sourcing their cores. Furthermore, since TSL 2 represents EL 3 for DL 7 and EL 2 for DL 8 (and baseline for DL 6), manufacturers may benefit from being able to standardize to NEMA Premium® levels for low-voltage dry-type distribution transformers.
After considering the analysis and weighing the benefits and the burdens, DOE has concluded that at TSL 2 for low-voltage dry-type distribution transformers, the benefits of energy savings, NPV of customer benefit, positive customer LCC impacts, emissions reductions and the estimated monetary value of the emissions reductions would outweigh the risk of small negative impacts on the manufacturers. In particular, DOE has concluded that TSL 2 would save a significant amount of energy and is technologically feasible and economically justified. For the reasons given above, DOE today adopts the energy conservation standards for low-voltage dry-type distribution transformers at TSL 2. Table V.43 presents the energy conservation standards for low-voltage dry-type distribution transformers.
Table V.44 and Table V.45 summarize the quantitative impacts estimated for each TSL for medium-voltage dry-type distribution transformers.
First, DOE considered TSL 5, the most efficient level (max tech), which would save an estimated total of 0.84 quad of energy, an amount DOE considers significant. TSL 5 has an estimated NPV of customer benefit of −$0.89 billion using a 7-percent discount rate, and −$0.20 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 5 are 61.3 million metric tons of CO
At TSL 5, the average LCC impact ranges from −$14,727 for design line 10 to −299 for design line 9. The median PBP ranges from 35.3 years for design line 13A to 18.5 years for design line 9. The share of customers experiencing a net LCC benefit ranges from 1.5 percent for design line 13A to 42.6 percent for design line 9.
At TSL 5, the projected change in INPV ranges from a decrease of $34 million to an increase of $13 million. If the decrease of $34 million occurs, TSL 5 could result in a net loss of 49.7 percent in INPV to manufacturers of medium-voltage dry-type distribution transformers. At TSL 5, DOE recognizes the risk of very large negative impacts on industry because they would likely be forced to move to amorphous core steel technology, with which there is no experience in this market.
In view of the foregoing, DOE concludes that, at TSL 5 for medium-voltage dry-type distribution transformers, the benefits of energy savings, generating capacity reductions, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the negative NPV of customer benefit, the economic burden on customers (as indicated by negative average LCC savings, large PBPs, and the large percentage of customers who would experience LCC increases), and the risk of very large negative impacts on the manufacturers. Consequently, DOE has concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4, which would save an estimated total of 0.53 quad of energy, an amount DOE considers significant. TSL 4 has an estimated NPV of customer benefit of $0.12 billion using a 7-percent discount rate, and $1.12 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 4 are 40.7 million metric tons of CO
At TSL 4, the average LCC impact ranges from −$1019 for design line 13A to $8,594 for design line 12. The median PBP ranges from 20.0 years for design line 13B to 6.1 years for design line 9. The share of customers experiencing a net LCC benefit ranges from 33.7 percent for design line 13A to 94.1 percent for design line 9.
At TSL 4, the projected change in INPV ranges from a decrease of $11 million to an increase of $6 million. If the decrease of $11 million occurs, TSL 4 could result in a net loss of 15.5 percent in INPV to manufacturers of medium-voltage dry-type distribution transformers. At TSL 4, DOE recognizes the risk of very large negative impacts on most manufacturers in the industry who have little experience with the steels that would be required. Small businesses, in particular, with limited engineering resources, may not be able to convert their lines to employ thinner steels and may be disadvantaged with respect to access to key materials, including Hi-B steels.
In view of the foregoing, DOE concludes that, at TSL 4 for medium-voltage dry-type distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive impacts on consumers (as indicated by positive average LCC savings, favorable PBPs, and the large percentage of customers who would experience LCC benefits), emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the risk of very large negative impacts on the manufacturers, particularly small businesses. Consequently, DOE has concluded that TSL 4 is not economically justified.
Next, DOE considered TSL 3, which would save an estimated total of 0.53 quad of energy, an amount DOE considers significant. TSL 3 has an estimated NPV of customer benefit of $0.12 billion using a 7-percent discount rate, and $1.12 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 3 are 40.7 million metric tons of CO
At TSL 3, the average LCC impact ranges from $311 for design line 13A to $8594 for design line 12. The median
At TSL 3, the projected change in INPV ranges from a decrease of $11 million to an increase of $6 million. If the decrease of $11 million occurs, TSL 3 could result in a net loss of 15.6 percent in INPV to manufacturers of medium-voltage dry-type transformers. At TSL 3, DOE recognizes the risk of large negative impacts on most manufacturers in the industry who have little experience with the steels that would be required. As with TSL 4, small businesses, in particular, with limited engineering resources, may not be able to convert their lines to employ thinner steels and may be disadvantaged with respect to access to key materials, including Hi-B steels.
In view of the foregoing, DOE concludes that, at TSL 3 for medium-voltage dry-type distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive impacts on consumers (as indicated by positive average LCC savings, favorable PBPs, and the large percentage of customers who would experience LCC benefits), emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the risk of large negative impacts on the manufacturers, particularly small businesses. Consequently, DOE has concluded that TSL 3 is not economically justified.
Next, DOE considered TSL 2, which would save an estimated total of 0.29 quads of energy, an amount DOE considers significant. TSL 2 has an estimated NPV of customer benefit of $0.17 billion using a 7-percent discount rate, and $0.79 billion using a 3-percent discount rate.
The cumulative emissions reductions at TSL 2 are 20.9 million metric tons of CO
At TSL 2, the average LCC impact ranges from $−27 for design line 13A to $6,790 for design line 12. The median PBP ranges from 16.1 years for design line 13A to 2.6 years for design line 9. The share of customers experiencing a net LCC benefit ranges from 45.8 percent for design line 13A to 92.4 percent for design line 12.
At TSL 2, the projected change in INPV ranges from a decrease of $3 million to an increase of $3 million. If the decrease of $3 million occurs, TSL 2 could result in a net loss of 4.2 percent in INPV to manufacturers of medium-voltage dry-type distribution transformers. At TSL 2, DOE recognizes the risk of small negative impacts if manufacturers are unable to recoup investments made to meet the standard.
After considering the analysis and weighing the benefits and the burdens, DOE has concluded that at TSL 2 for medium-voltage dry-type distribution transformers, the benefits of energy savings, positive NPV of customer benefit, positive impacts on consumers (as indicated by positive average LCC savings for five of the six design lines, favorable PBPs, and the large percentage of customers who would experience LCC benefits), emission reductions, and the estimated monetary value of the emissions reductions would outweigh the risk of small negative impacts if manufacturers are unable to recoup investments made to meet the standard. In particular, DOE has concluded that TSL 2 would save a significant amount of energy and is technologically feasible and economically justified. In addition, DOE notes that TSL 2 corresponds to the standards that were agreed to by the DOE Efficiency and Renewables Advisory Committee (ERAC) subcommittee, as described in section II.B.2. Based on the above considerations, DOE today adopts the energy conservation standards for medium-voltage dry-type distribution transformers at TSL 2. Table V.46 presents the energy conservation standards for medium-voltage dry-type distribution transformers.
The benefits and costs of today's standards can also be expressed in terms of annualized values. The annualized monetary values are the sum of: (1) the annualized national economic value of the benefits from operating products that meet today's standards (consisting primarily of operating cost savings from using less energy, minus increases in equipment purchase costs, which is another way of representing customer NPV); and (2) the monetary value of the benefits of emission reductions, including CO
Although combining the values of operating savings and CO
Table V.47 shows the annualized values for today's standards for distribution transformers. The results for the primary estimate are as follows. Using a 7-percent discount rate for benefits and costs (other than CO
Section 1(b)(1) of Executive Order 12866, “Regulatory Planning and Review,” 58 FR 51735 (Oct. 4, 1993), requires each agency to identify the problem that it intends to address, including, where applicable, the failures of private markets or public institutions that warrant new agency action, as well as to assess the significance of that problem. The problems addressed by today's standards are as follows:
(1) There is a lack of consumer information and/or information processing capability about energy efficiency opportunities in the commercial equipment market.
(2) There is asymmetric information (one party to a transaction has more and better information than the other) and/or high transactions costs (costs of gathering information and effecting exchanges of goods and services).
(3) There are some external benefits resulting from improved energy efficiency of distribution transformers that are not captured by the users of such equipment. These benefits include externalities related to environmental protection and energy security that are not reflected in energy prices, such as reduced emissions of greenhouse gases.
The specific market failure that the energy conservation standard addresses for distribution transformers is that a substantial portion of distribution transformer purchasers are not evaluating the cost of transformer losses when they make distribution transformer purchase decisions. Consequently, distribution transformers are being purchased that do not provide the minimum LCC to the equipment owners.
For distribution transformers, the Institute of Electronic and Electrical Engineers Inc. (IEEE) has documented voluntary guidelines for the economic evaluation of distribution transformer losses, IEEE PC57.12.33/D8. These guidelines document economic evaluation methods for distribution transformers that are common practice in the utility industry. But while economic evaluation of transformer losses is common, it is not a universal practice. DOE collected information during the course of the previous energy conservation standard rulemaking to estimate the extent to which distribution transformer purchases are evaluated. Data received from NEMA indicated that these guidelines or similar criteria are applied to approximately 75 percent of liquid-immersed distribution transformer purchases, 50 percent of small capacity medium-voltage dry-type transformer purchases, and 80 percent of large capacity medium-voltage dry-type transformer purchases. Therefore, 25 percent, 50 percent, and 20 percent of such purchases in these segments do not employ economic evaluation of transformer losses. These are the portions of the distribution transformer market in which there is market failure. Today's energy conservation standards would eliminate from the market those distribution transformers designs that are purchased on a purely minimum first cost basis, but which would not likely be purchased by equipment buyers when the economic value of equipment losses are properly evaluated.
In addition, DOE has determined that today's regulatory action is an “economically significant regulatory action” under section 3(f)(1) of Executive Order 12866. Accordingly, section 6(a)(3) of the Executive Order requires that DOE prepare a regulatory impact analysis (RIA) on today's rule and that the Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget (OMB) review this rule. DOE presented to OIRA for review the draft rule and other documents prepared for this rulemaking, including the RIA, and has included these documents in the rulemaking record. The assessments prepared pursuant to Executive Order 12866 can be found in the technical support document for this rulemaking.
DOE has also reviewed this regulation pursuant to Executive Order 13563, issued on January 18, 2011 (76 FR 3281, Jan. 21, 2011). EO 13563 is supplemental to and explicitly reaffirms the principles, structures, and definitions governing regulatory review established in Executive Order 12866. To the extent permitted by law, agencies are required by Executive Order 13563 to: (1) Propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing information upon which choices can be made by the public.
DOE emphasizes as well that Executive Order 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, the Office of Information and Regulatory Affairs has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, DOE believes that today's final rule is consistent with these principles, including the requirement that, to the extent permitted by law, benefits justify costs and that net benefits are maximized.
The Regulatory Flexibility Act (5 U.S.C. 601
As presented and discussed in the following sections, the FRFA describes potential impacts on small manufacturers associated with the required product and capital conversion costs at each TSL and discusses alternatives that could minimize these impacts. Chapter 12 of the TSD contains
The reasons why DOE is establishing the standards in today's final rule and the objectives of these standards are provided elsewhere in the preamble and not repeated here.
This FRFA incorporates the IRFA and public comments received on the IRFA and the economic impacts of the rule. DOE provides responses to these comments in the discussion below on the compliance impacts of the rule and elsewhere in the preamble. DOE modified the standards adopted in today's final rule in response to comments received, including those from small businesses, as described in the preamble.
For manufacturers of distribution transformers, the Small Business Administration (SBA) has set a size threshold, which defines those entities classified as “small businesses” for the purposes of the statute. DOE used the SBA's small business size standards to determine whether any small entities would be subject to the requirements of the rule. 65 FR 30836, 30848 (May 15, 2000), as amended at 65 FR 53533, 53544 (Sept. 5, 2000) and codified at 13 CFR part 121. The size standards are listed by NAICS code and industry description and are available at
In the February 2012 NOPR, DOE identified approximately 10 liquid-immersed distribution transformer manufacturers, 14 LVDT manufacturers, and 17 MVDT manufacturers of covered equipment that can be considered small businesses. 77 FR 7282 (February 10, 2012). Of the liquid-immersed distribution transformer small business manufacturers, DOE was able to reach and discuss potential standards with six of the 10 small business manufacturers. Of the LVDT manufacturers, DOE was able to contact and discuss potential standards with seven of the 14 small business manufacturers. Of the MVDT manufacturers, DOE was able to reach and discuss potential standards with five of the 17 small business manufacturers. DOE also obtained information about small business impacts while interviewing large manufacturers.
Six major manufacturers supply more than 80 percent of the market for liquid-immersed transformers. None of the major manufacturers of distribution transformers covered in this rulemaking are considered to be small businesses. The vast majority of shipments are manufactured domestically. Electric utilities compose the customer base and typically buy on first-cost. Many small manufacturers position themselves towards the higher end of the market or in particular product niches, such as network transformers or harmonic mitigating transformers, but, in general, competition is based on price after a given unit's specifications are prescribed by a customer.
Four major manufacturers supply more than 80 percent of the market for low-voltage dry-type transformers. None of the major manufacturers of LVDT distribution transformers covered in this rulemaking are small businesses. The customer base rarely purchases on efficiency and is very first-cost conscious, which, in turn, places a premium on economies of scale in manufacturing. DOE estimates approximately 80 percent of the market is served by imports, mostly from Canada and Mexico. Many of the small businesses that compete in the low-voltage dry-type market produce specialized transformers that are not covered under standards. Roughly 50 percent of the market by revenue is not covered under DOE standards. This market is much more fragmented than the one serving DOE-covered LVDT transformers.
In the DOE-covered LVDT market, low-volume manufacturers typically do not compete directly with large manufacturers using business models similar to those of their bigger rivals because scale disadvantages in purchasing and production are usually too great a barrier in this portion of the market. The exceptions to this rule are those companies that also compete in the medium-voltage market and, to some extent, are able to leverage that experience and production economies. More typically, low-volume manufacturers focus their operations on one or two parts of the value chain—rather than all of it—and focus on market segments outside of the high-volume baseline efficiency market.
In terms of operations, some small firms focus on the engineering and design of transformers and source the production of the cores or even the whole transformer, while other small firms focus on just production and rebrand for companies that offer broader solutions through their own sales and distribution networks.
In terms of market focus, many small firms compete entirely in distribution transformer markets that are not covered by statute. DOE did not attempt to contact companies operating solely in this very fragmented market. Of those that do compete in the DOE-covered market, a few small businesses reported a focus on the high-end of the market, often selling NEMA Premium® (equivalent to EL3, EL3, and EL2 for DL6, DL7 and DL8, respectively) or better transformers as retrofit opportunities. Others focus on particular applications or niches, like data centers, and become well-versed in the unique needs of a particular customer base.
The medium-voltage dry-type transformer market is relatively consolidated with one large company holding a substantial share of the market. Electric utilities and industrial users make up most of the customer base and typically buy on first-cost or features other than efficiency. DOE estimates that at least 75 percent of production occurs domestically. Several manufacturers also compete in the power transformer market. Like the LVDT industry, most small business manufacturers in the MVDT industry often produce transformers not covered under DOE standards. DOE estimates that 10 percent of the market is not covered under standards.
Small distribution transformer manufacturers differ from large manufacturers in several ways that affect the extent to which they would be impacted by the proposed standards. Characteristics of small manufacturers include: lower production volumes, fewer engineering resources, less technical expertise, lack of purchasing power for high performance steels, and less access to capital.
Lower production volumes are the root cause of most small business
Smaller companies are also more likely to have more limited engineering resources and they often operate with lower levels of design and manufacturing sophistication. Smaller companies typically also have less experience and expertise in working with more advanced technologies, such as amorphous core construction in the liquid-immersed market or step-lap mitering in the dry-type markets. Standards that required these technologies could strain the engineering resources of these small manufacturers if they chose to maintain a vertically integrated business model.
Small distribution transformer manufacturers can also be at a disadvantage due to their lack of purchasing power for high performance materials. If more expensive steels are needed to meet standards and steel cost grows as a percentage of the overall product cost, small manufacturers who pay higher per pound prices would be disproportionately impacted.
Last, small manufacturers typically have less access to capital, which may be needed by some to cover the conversion costs associated with new technologies.
Based on interviews with manufacturers in the liquid-immersed market, DOE does not believe small manufacturers will face significant capital conversion costs at the levels established in today's rulemaking. DOE expects small manufacturers of liquid-immersed distribution transformers to continue to produce silicon steel cores, rather than invest in amorphous technology. While silicon steel designs capable of achieving TSL 1 would get larger, and thus reduce throughput, most manufacturers said the industry in general has substantial excess capacity due to the recent economic downturn. Therefore, DOE believes TSL 1 would not require the typical small manufacturer to invest in additional capital equipment. However, small manufacturers may incur some engineering and product design costs associated with re-optimizing their production processes around new baseline equipment. DOE estimates TSL 1 would require industry product conversion costs of only one-half of one year's annual industry R&D expenses. Because these one-time costs are relatively fixed per manufacturer, they impact smaller manufacturers disproportionately (compared to larger manufacturers). The table below illustrates this effect:
While the costs disproportionately impact small manufactures, the standard levels, as stated above, do not require small manufacturers to invest in entirely different production processes nor do they require steels or core construction techniques with which these manufacturers are not familiar. A range of design options would still be available.
b. Low-Voltage Dry-Type.
Small manufacturers have several options available to them at TSL2 based on individual economic determinations. They may choose to: (1) Source their cores, (2) fabricate cores with butt-lapping technology and higher-grade steel, (3) buy a mitering machine (enabling them to build mitered cores with lower-grade steel than would be otherwise required), or (4) exit a product line.
Compared to higher TSLs, TSL 2 provides many more design paths for small manufacturers to comply. DOE's engineering analysis indicates that the efficiency level represented by TSL 2 for DL7 (the high-volume line) could be met without mitering through the use of butt-lapping higher-grade steels. It is uncertain whether small manufacturers would elect to butt-lap with higher grade steel rather than source their cores or invest in mitering equipment, but each option remains a viable path to compliance. With respect to the other paths to compliance, DOE notes that roughly half of the small business LVDT manufacturers DOE interviewed already have mitering capability. DOE estimates half of all cores in small business DL7 transformers are currently sourced, according to transformer and core manufacturer interviews, as third-party core manufacturers already often have significant variable cost advantages through bulk steel purchasing power and greater production efficiencies due to higher volumes.
Each business' ultimate decision on how it will ultimately comply depends on its production volumes, the relative steel prices it faces, its position in the value chain, and whether it currently has mitering technology in-house, among other factors. Because a small business may ultimately make the business decision to build mitered cores at TSL 2, DOE estimates the cost of such a strategy to conservatively bound the compliance impact. Below DOE compares the relative impact on a small business of the scenario in which a small manufacturer elects to purchase a new mitering machine (rather than continue to butt-lap with higher grade steel or source its core production). Based on interviews with small businesses and core manufacturers, DOE believes this to be a conservative assessment of compliance costs, as many small businesses currently source a large share of their cores. DOE estimates capital conversion costs of $0.75 million and product conversion costs of $0.2 million, based on manufacturer and equipment supplier interviews, would be incurred if small businesses without mitering equipment chose to invest in it. Because of the largely fixed nature of these one-time conversion expenditures that distribution transformer manufacturers would incur as a result of standards, small manufacturers who choose to invest in in-house mitering capability will likely be disproportionately impacted (compared to large manufacturers). Based on information gathered in interviews, DOE estimates that three small manufacturers would invest in mitering equipment as result of this rule. As Table VI.2 indicates, small manufacturers face a greater relative hurdle in complying with standards should they opt to continue to maintain core production in-house.
For more than half of the small businesses DOE interviewed, it is already standard practice to source a large percentage of their DOE-covered cores on an ongoing basis or quickly do so when steel prices merit such a strategy. Furthermore, small businesses are currently more likely to source cores for NEMA Premium® units than standard units. Many small businesses indicated that they expect the continuance of this strategy would be the low-cost option under higher standards. Therefore, the impacts in the table are not representative of the strategy DOE expects to be employed by many small manufacturers, but only those choosing to invest in mitering equipment.
For all of the reasons discussed, DOE believes the capital expenditures it estimated above for small businesses are likely conservative and that small businesses have a variety of technical and strategic paths to continue to compete in the market at TSL 2.
Based on its engineering analysis and interviews, DOE expects relatively minor capital expenditures for the industry to meet TSL 2. DOE understands that the market is already standardized on step-lap mitering, so manufacturers will not need to make major investments for more advanced core construction. Furthermore, TSL 2 does not require a change to much thinner steels such as M3 or H0. The industry can use M4 and H1, thicker steels with which it has much more experience and which are easier to employ in the stacked-core production process that dominates the medium-voltage market. However, some investment will be required to maintain capacity as some manufacturers will likely migrate towards more M4 and H1 steel and away from the slightly thicker M5, which is also common. Additionally, design options at TSL 2 typically have larger cores, also slowing throughput. Therefore, some manufacturers may need to invest in additional production equipment. Alternatively, depending on each company's availability capacity, manufacturers could employ additional production shifts, rather than invest in additional capacity.
For the medium-voltage dry-type market, at TSL 2, the level proposed in today's notice, DOE estimates low capital and product conversion costs that are relatively fixed for both small and large manufacturers. Similar to the low-voltage dry-type market, small manufacturers will likely be disproportionately impacted compared to large manufacturers due to the fixed nature of the conversion expenditures. Table VI.3 illustrates the relative impacts on small and large manufacturers.
The compliance impacts on small businesses are discussed above for low-voltage dry-type, medium-voltage dry-type, and liquid-filled distribution transformer manufacturers. Although the conversion costs required can be considered substantial for both large and small companies, the impacts could be relatively greater for a typical small manufacturer because of much lower production volumes and the relatively fixed nature of the R&D and capital investments required.
DOE modified the standards established in today's final rule from those proposed in the February 2012 NOPR as discussed previously and based on comments and additional test data received from interested parties.
The previous discussion also analyzes impacts on small businesses that would result from the other TSLs DOE considered. Though TSLs lower than the adopted TSL are expected to reduce the impacts on small entities, DOE is required by EPCA to establish standards that achieve the maximum improvement in energy efficiency that are technically feasible and economically justified, and result in a significant conservation of energy. Thus, DOE rejected the lower TSLs.
In addition to the other TSLs being considered, the TSD includes a regulatory impact analysis (chapter 17) that discusses the following policy alternatives: (1) No standard, (2) consumer rebates, (3) consumer tax credits, (4) manufacturer tax credits, and (5) early replacement. DOE does not intend to consider these alternatives further because they are either not feasible to implement, or not expected to result in energy savings as large as those that would be achieved by the standard levels under consideration. Thus, DOE rejected these alternatives and is adopting the standards set forth in this rulemaking.
DOE is not aware of any rules or regulations that duplicate, overlap, or conflict with the rule being finalized today.
The discussion above analyzes impacts on small businesses that would result from the other TSLs DOE considered. Though TSLs lower than the selected TSLs are expected to reduce the impacts on small entities, DOE is required by EPCA to establish standards that achieve the maximum improvement in energy efficiency that are technically feasible and economically justified, and result in a significant conservation of energy. Therefore, DOE rejected the lower TSLs.
In addition to the other TSLs being considered, the TSD includes a regulatory impact analysis (chapter 17) that discusses the following policy alternatives: (1) Consumer rebates, (2) consumer tax credits, and (3) manufacturer tax credits. DOE does not intend to consider these alternatives further because they either are not feasible to implement or are not expected to result in energy savings as large as those that would be achieved by the standard levels under consideration.
DOE's MIA suggests that, while TSL1, TSL1, and TSL 2 present greater difficulties for small businesses than lower levels in the liquid-immersed, LVDT, and MVDT classes, respectively, the impacts at higher TSLs would be greater. DOE expects that small businesses will generally be able to profitably compete at the TSL selected in today's rulemaking. DOE's MIA is based on its interviews of both small and large manufacturers, and consideration of small business impacts explicitly enters into DOE's choice of the TSLs selected in this final rule.
DOE also notes that today's standards can be met with a variety of materials, including multiple core steels and both copper and aluminum windings. Because today's TSLs can be met with a variety of materials, DOE does not expect that material availability issues will be a problem for the industry that results from this rulemaking.
In consideration of the benefits and burdens of standards, including the burdens posed to small manufacturers, DOE concluded that TSL1 is the highest level that can be justified for liquid-immersed and medium-voltage dry-type transformers and TSL2 is the highest level that can be justified for low-voltage dry-type transformers. As explained in part 6 of the IRFA, “Significant Alternatives to the Rule,” DOE explicitly considered the impacts on small manufacturers of liquid-immersed and dry-type transformers in selecting the TSLs in today's rulemaking, rather than selecting a higher trial standard level. It is DOE's belief that levels at TSL3 or higher would place excessive burdens on small manufacturers of medium-voltage dry-type transformers, as would TSL 2 or higher for liquid-immersed and medium-voltage dry-type transformers. Such burdens would include large product redesign costs and also operational problems associated with the extremely thin laminations of core steel that would be needed to meet these levels and advanced core construction equipment and tooling for mitering, or wound-core designs. Similarly, for medium-voltage dry-type, the steels and construction techniques likely to be used at TSL 2 are already commonplace in the market, whereas TSL 3 would likely trigger a more dramatic shift to thinner and more exotic steels, to which many small businesses have limited access. Lastly, DOE is confident that TSL1 for the liquid-immersed distribution transformer market would not require small manufacturers to invest in amorphous steel technology, which could put them at a significant disadvantage.
Section VI.B discusses how small business impacts entered into DOE's selection of today's standards for distribution transformers. DOE made its decision regarding standards by beginning with the highest level considered and successively eliminating TSLs until it found a TSL that is both technologically feasible and economically justified, taking into account other EPCA criteria. Because DOE believes that the TSLs selected are economically justified (including consideration of small business impacts), the reduced impact on small businesses that would have been realized in moving to lower efficiency levels was not considered in DOE's decision (but the reduced impact on small businesses that is realized in moving down to TSL2 from TSL3 (in the case of medium-voltage dry-type and low-voltage dry-type) and to TSL1 from TSL2 (in the case of liquid-immersed) was explicitly considered in the weighing of benefits and burdens).
Manufacturers of distribution transformers must certify to DOE that their equipment complies with any applicable energy conservation standards. In certifying compliance, manufacturers must test their equipment according to the DOE test procedures for distribution transformers, including any amendments adopted for those test procedures. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including distribution transformers. (76 FR 12422 (March 7, 2011). The collection-of-information requirement for the certification and recordkeeping is subject to review and approval by OMB under the Paperwork Reduction Act (PRA). This requirement has been approved by OMB under OMB control number 1910–1400. Public reporting burden for the certification is estimated to average 20 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information.
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.
Pursuant to the National Environmental Policy Act (NEPA) of 1969, DOE has determined that the rule fits within the category of actions included in Categorical Exclusion (CX) B5.1 and otherwise meets the requirements for application of a CX. See 10 CFR part 1021, App. B, B5.1(b); 1021.410(b) and Appendix B, B(1)–(5). The rule fits within the category of actions because it is a rulemaking that establishes energy conservation standards for consumer products or industrial equipment, and for which none of the exceptions identified in CX B5.1(b) apply. Therefore, DOE has made a CX determination for this rulemaking, and DOE does not need to prepare an Environmental Assessment or Environmental Impact Statement for this rule. DOE's CX determination for this rule is available at
Executive Order 13132, “Federalism.” 64 FR 43255 (Aug. 10, 1999) imposes certain requirements on Federal
With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” imposes on Federal agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity; (2) write regulations to minimize litigation; and (3) provide a clear legal standard for affected conduct rather than a general standard and promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Section 3(b) of Executive Order 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any; (2) clearly specifies any effect on existing Federal law or regulation; (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction; (4) specifies the retroactive effect, if any; (5) adequately defines key terms; and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law, this final rule meets the relevant standards of Executive Order 12988.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Pub. L. 104–4, sec. 201 (codified at 2 U.S.C. 1531). For an amended regulatory action likely to result in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect small governments. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy statement is also available at
DOE has concluded that this final rule would likely require expenditures of $100 million or more by the private sector. Such expenditures may include: (1) investment in research and development and in capital expenditures by distribution transformer manufacturers in the years between the final rule and the compliance date for the new standards, and (2) incremental additional expenditures by consumers to purchase higher-efficiency distribution transformers, starting at the compliance date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the content requirements of UMRA in any other statement or analysis that accompanies the final rule. 2 U.S.C. 1532(c). The content requirements of section 202(b) of UMRA relevant to a private sector mandate substantially overlap the economic analysis requirements that apply under section 325(o) of EPCA and Executive Order 12866. The
Under section 205 of UMRA, the Department is obligated to identify and consider a reasonable number of regulatory alternatives before promulgating a rule for which a written statement under section 202 is required. 2 U.S.C. 1535(a). DOE is required to select from those alternatives the most cost-effective and least burdensome alternative that achieves the objectives of the rule unless DOE publishes an explanation for doing otherwise, or the selection of such an alternative is inconsistent with law. As required by 42 U.S.C. 6295 (o), 6316(a), and 6317(a)(1), today's final rule would establish energy conservation standards for distribution transformers that are designed to achieve the maximum improvement in energy efficiency that DOE has determined to be both technologically feasible and economically justified. A full discussion of the alternatives considered by DOE is presented in the “Regulatory Impact Analysis” chapter of the TSD for today's final rule.
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105–277) requires Federal agencies to issue a Family Policymaking Assessment for any rule that may affect family well-being. This rule would not have any impact on the autonomy or integrity of the family as an institution. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.
DOE has determined, under Executive Order 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights” 53 FR 8859 (March 18, 1988), that this regulation would not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.
Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to review most disseminations of information to the public under guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's
Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that: (1) Is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.
DOE has concluded that today's regulatory action, which sets forth energy conservation standards for distribution transformers, is not a significant energy action because the amended standards are not likely to have a significant adverse effect on the supply, distribution, or use of energy, nor has it been designated as such by the Administrator at OIRA. Accordingly, DOE has not prepared a Statement of Energy Effects for the final rule.
On December 16, 2004, OMB, in consultation with the Office of Science and Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review (the Bulletin). 70 FR 2664 (January 14, 2005). The Bulletin establishes that certain scientific information shall be peer reviewed by qualified specialists before it is disseminated by the Federal Government, including influential scientific information related to agency regulatory actions. The purpose of the bulletin is to enhance the quality and credibility of the Government's scientific information. Under the Bulletin, the energy conservation standards rulemaking analyses are “influential scientific information,” which the Bulletin defines as scientific information the agency reasonably can determine will have, or does have, a clear and substantial impact on important public policies or private sector decisions. 70 FR 2667.
In response to OMB's Bulletin, DOE conducted formal in-progress peer reviews of the energy conservation standards development process and analyses and has prepared a Peer Review Report pertaining to the energy conservation standards rulemaking analyses. Generation of this report involved a rigorous, formal, and documented evaluation using objective criteria and qualified and independent reviewers to make a judgment as to the technical/scientific/business merit, the actual or anticipated results, and the productivity and management effectiveness of programs and/or projects. The “Energy Conservation Standards Rulemaking Peer Review Report” dated February 2007 has been disseminated and is available at the following Web site:
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this rule prior to its effective date. The report will state that it has been determined that the rule is a “major rule” as defined by 5 U.S.C. 804(2).
The Secretary of Energy has approved publication of today's final rule.
Administrative practice and procedure, Confidential business information, Energy conservation, Reporting and recordkeeping requirements.
For the reasons set forth in the preamble, DOE amends part 431 of chapter II, of title 10 of the Code of Federal Regulations, to read as set forth below:
42 U.S.C. 6291–6317.
(a)
(2) The efficiency of a low-voltage dry-type distribution transformer manufactured on or after January 1, 2016, shall be no less than that required for their kVA rating in the table below. Low-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
(b)
(2) The efficiency of a liquid-immersed distribution transformer manufactured on or after January 1, 2016, shall be no less than that required for their kVA rating in the table below. Liquid-immersed distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
(c)
(2) The efficiency of a medium- voltage dry-type distribution transformer manufactured on or after January 1, 2016, shall be no less than that required for their kVA and BIL rating in the table below. Medium-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
(d)
The following letter from the Department of Justice will not appear in the Code of Federal Regulations.
I am responding to your August 16, 2012 letter seeking the views of the Attorney General about the potential impact on competition of proposed energy conservation standards for certain types of distribution transformers, namely medium-voltage, dry-type and liquid-immersed distribution transformers, as well as low-voltage, dry-type distribution transformers. Your request was submitted under Section 325(o)(2)(B)(i)(V) of the Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C. 6295(o)(2)(B)(i)(V), which requires the Attorney General to make a determination of the impact of any lessening of competition that is likely to result from the imposition of proposed energy conservation standards. The Attorney General's responsibility for responding to requests from other departments about the effect of a program on competition has been delegated to the Assistant Attorney General for the Antitrust Division in 28 CFR § 0.40(g).
In conducting its analysis the Antitrust Division examines whether a proposed standard may lessen competition, for example, by substantially limiting consumer choice, by placing certain manufacturers at an unjustified competitive disadvantage, or by inducing avoidable inefficiencies in production or distribution of particular products. A lessening of competition could result in higher prices to manufacturers and consumers, and perhaps thwart the intent of the revised standards by inducing substitution to less efficient products.
We have reviewed the proposed standards contained in the Notice of Proposed Rulemaking (77 Fed. Reg. 7282, February 10, 2012) (NOPR). We have also reviewed supplementary information submitted to the Attorney General by the Department of Energy. The NOPR proposed Trial Standard Level 2 for medium-voltage, dry-type distribution transformers, which was arrived at through a consensus agreement among a diverse array of stakeholders as part of a negotiated rulemaking, and Trial Standard Level 1 for medium-voltage, liquid-immersed and low-voltage, dry-type distribution transformers, after no consensus was reached as part of a negotiated rulemaking. Our review has focused on the standards DOE has proposed adopting. We have not determined the impact on competition of more stringent standards than those proposed in the NOPR.
Based on this review, our conclusion is that the proposed energy conservation standards for medium-voltage, dry-type and liquid-immersed distribution transformers, as well as low-voltage, dry-type distribution transformers, are unlikely to have a significant adverse impact on competition. In reaching our conclusion, we note that the proposed energy standards for medium-voltage, dry-type distribution transformers were arrived at through a consensus agreement among a diverse array of stakeholders.
Farm Credit Administration.
Final rule.
The Farm Credit Administration (FCA, we or us) adopts a final rule that amends its liquidity regulation. The purpose of the final rule is to strengthen liquidity risk management at Farm Credit System (FCS, Farm Credit, or System) banks, improve the quality of assets in their liquidity reserves, and bolster the ability of System banks to fund their obligations and continue operations during times of economic, financial, or market adversity.
The objectives of the final rule are to:
• Improve the capacity of FCS banks to pay their obligations and fund their operations by maintaining adequate liquidity to withstand various market disruptions and adverse economic or financial conditions;
• Strengthen liquidity management at all FCS banks;
• Enhance the liquidity of assets that System banks hold in their liquidity reserves;
• Require FCS banks to maintain a three-tiered liquidity reserve. The first tier of the liquidity reserve must consist of a sufficient amount of cash and cash-like instruments to cover each bank's financial obligations for 15 days. The second and third tiers of the liquidity reserve must contain cash and highly liquid instruments that are sufficient to cover the bank's obligations for the next 15 and subsequent 60 days, respectively;
• Establish a supplemental liquidity buffer that a bank can draw upon during an emergency and is sufficient to cover the bank's liquidity needs beyond 90 days; and
• Strengthen each bank's Contingency Funding Plan (CFP).
The FCS is a nationwide network of borrower-owned financial cooperatives that lend to farmers, ranchers, aquatic producers and harvesters, agricultural cooperatives, rural utilities, farm-related service businesses, and rural homeowners. Its primary purpose is to furnish “sound, adequate, and constructive credit and closely related services” necessary for efficient agricultural operations in the United States.
FCS banks issue Systemwide debt securities, which are the primary source of funding System loans to farmers, ranchers, cooperatives, and other eligible borrowers.
We have periodically amended our liquidity rule over the past 19 years as part of our ongoing efforts to limit the adverse effect that changing economic, financial, or market conditions have on the liquidity of FCS banks.
(1) Require FCS banks to manage their liquidity reserves primarily as an emergency source of funding;
(2) Require boards to adopt stronger and more focused policies concerning liquidity management and the contingency funding plan;
(3) Divide the 90-day liquidity reserve into tiers so each FCS bank has a sufficient amount of cash and cash-like instruments available to pay its obligations and fund its operations for the next 15 days, and maintain a pool of cash or highly liquid instruments for the subsequent 15 days and the 60 days after that;
(4) Require each FCS bank to establish and maintain a supplemental liquidity buffer that would provide a longer term, stable source of funding beyond the 90-day minimum liquidity reserve; and
(5) Specify corrective actions that the FCA could compel FCS banks to
The four System banks and the Farm Credit Council (Council) commented on the proposed rule. All five commenters acknowledge sound liquidity management enables the FCS to fulfill its statutory mandate to fund agriculture. As the FCA noted in the preamble to the proposed rule, the commenters emphasized that all FCS banks withstood the financial crisis of 2008 with their liquidity intact. The commenters attribute this success to effective liquidity management at FCS banks and the current regulatory framework, which they deem to be appropriate. For this reason, the commenters suggest that the FCA should make only minor adjustments to the existing liquidity regulation, § 615.5134, rather than comprehensive revisions. In this context, all commenters expressed the view that the proposed rule is excessive, complex, and overly prescriptive.
The commenters also claim that the FCA's proposal would result in undue regulatory burden on System banks because it goes far beyond what they believe is necessary for effective liquidity risk management. The commenters raised a number of substantive issues about the proposed liquidity rule, and they recommended specific revisions for the final rule. The main areas of concern that the commenters raised are:
• The proper roles of both board and management in devising and implementing liquidity policies for the bank;
• The extent to which FCS banks should distinguish or segregate investments held for liquidity management from investments held for other purposes;
• The role of short-term discount notes in the funding strategies of Farm Credit banks;
• The extent to which guidance from the Basel Committee on Banking Supervision (Basel Committee) and the Federal banking regulators
• The lack of a lender of last resort for FCS banks;
• GSE status and the extent to which Farm Credit banks should generate earnings from their investments; and
• Development of a consistent regulatory approach for liquidity at both FCS banks and the Federal Agricultural Mortgage Corporation (Farmer Mac).
The commenters have not persuaded the FCA that the proposed rule is unduly burdensome or overly prescriptive, or that only minor adjustments to the existing liquidity regulation are warranted. Recent financial crises and continuing global economic uncertainty clearly demonstrate that strong liquidity management practices and access to reliable sources of emergency funding are crucial both to the viability of each financial institution, including FCS banks, and to the financial system as a whole. We proposed substantial revisions to § 615.5134 in order to redress vulnerabilities in liquidity management that we identified at System banks in the aftermath of the 2008 crisis.
The commenters offered many constructive and practical suggestions for improving the regulation that we incorporated into the final rule. Based on these comments, we restructured and refined the rule to make it easier to read, understand, and implement. Additionally, the comments caused us to reconsider and revise some of our positions. As we explain the final rule and how it differs from our original proposal, we will respond to comments about our overall regulatory and supervisory approach to liquidity as well as specific issues arising from each provision of § 615.5134.
Liquidity refers to the ability of financial institutions to pay obligations and fund operations on an ongoing basis at a reasonable cost. Recent financial crises demonstrate how quickly liquidity can vanish at seemingly strong financial institutions, which could impair their viability and jeopardize their survival. If economic or financial conditions quickly or unexpectedly deteriorate, financial institutions may find that their routine funding sources have become too scarce or costly, and that they then do not have sufficient liquid assets to meet their immediate funding needs. This lack of adequate liquidity can threaten the safety and soundness of individual institutions, and the financial system as a whole.
The FCA noted in the preamble to the proposed rule that throughout the 2008 crisis, FCS banks were able to raise funds and pay their obligations in a timely manner. However, the FCA and System commenters drew very different conclusions from the 2008 crisis, especially concerning whether FCS banks need to strengthen both their liquidity reserves and their liquidity risk management practices so they are in the best position possible to weather future financial and economic storms. The FCA identified several vulnerabilities at FCS banks that could adversely affect their liquidity during economic, financial, or market turmoil in the future. For this reason, the FCA proposed to correct these potential weaknesses by proposing substantial revisions to § 615.5134.
In contrast, FCS commenters concluded that the crisis in 2008 vindicated the existing liquidity regulation. Three commenters attribute effective risk management practices under the existing regulatory framework as the reason why System banks had adequate liquidity to continue operations without disruptions throughout the 2008 crisis. Additionally, these commenters point out that System banks, on their own initiative, implemented various measures to improve their liquidity management practices so they could continue their operations unabated whenever financial markets became distressed. For example, FCS banks refined the liquidity standards and measures in the Contractual Interbank Performance Agreement (CIPA).
Although FCS banks survived the 2008 crisis with their liquidity intact under the existing regulatory framework, the FCA observes that it is not necessarily an adequate or effective bulwark against future market disruptions that would most likely occur under different circumstances. In 2008, the agricultural economy was strong and the System was sound when the housing bubble burst, causing a financial crisis that imperiled the liquidity of the global financial system. In these circumstances, FCS banks were able to continue issuing debt (overwhelmingly short-term discount notes) to investors, who remained confident in the System's ability to meet its obligations, but even then, most investors were only willing to buy very short-term instruments.
In other plausible scenarios, however, distress in the agriculture sector could reduce the income of FCS banks and associations, thus making it more difficult for affected System institutions to pay their debts and fund their operations. As a result, the System's funding costs could rise as investor confidence becomes shaken, and market access could become partially or fully impeded. One or more of the following events could impair the liquidity of System banks:
• A steep drop in commodity prices that adversely affects the repayment capacity of a large percentage of FCS borrowers, thereby reducing the ability of System banks to repay their obligations and fund their operations;
• Extended declines in both commodity prices and agricultural land values would result in significant loan losses at FCS banks and associations, thereby impairing System capital and impeding market access;
• A sudden surge in borrower demand for funds under lines of credit that strains the bank's ability to meet these unfunded commitments at a time of market stress; or
• A large amount of System obligations become due and payable as a severe market disruption is reaching its peak.
Any of these events could impair the viability of one or more FCS banks, thereby constricting the System's capacity to fund its normal operations. Substantially revising and strengthening § 615.5134 mitigates the System's vulnerabilities to such risks, and thereby improves the System's ability to withstand market disruptions in a wide range of circumstances.
The FCA supports the measures that System banks implemented to strengthen liquidity. In our view, the System's efforts and our new regulation complement each other. For example, revised § 615.5134 divides the liquidity reserve into tiers that are similar to the tiers that FCS banks have already established. Additionally, the regulation reinforces enhanced practices at FCS banks to hold more cash and highly liquid investments in amounts sufficient to cover obligations maturing in the next 15, 30, and 90 days.
The rule also strengthens internal controls and risk management practices at System banks. Under the revised regulation, System banks will retain ample flexibility to manage liquidity effectively in future crises, and adjust their strategies to changing circumstances. The new regulation enables FCS banks to further refine CIPA, or make adjustments to debt maturities or investments, as circumstances warrant. As amended, § 615.5134 promotes comprehensive and sound liquidity management at FCS banks. For this reason, our new regulation aids, rather than hinders System banks as they combat liquidity risks in an ever-changing environment.
The preamble to the proposed rule frequently referred to guidance that international and Federal regulators developed to enhance liquidity management practices at the financial institutions they regulate. In September 2008, the Basel Committee issued the
We received several comments about the extent to which Basel III and the approach of other regulators influences our new liquidity regulation. System commenters expressed conflicting opinions on this issue. One bank opined that the proposed rule is “too detailed and prescriptive compared to the principles-based approach” of other bank regulators. In contrast, two commenters applauded the FCA's efforts to create regulatory requirements for liquidity that are similar to the approach of the Basel Committee and the Federal banking agencies, when it is appropriate to do so. However, they cautioned the FCA not to “get ahead of these regulators with respect to their consideration and implementation of Basel III.” A commenter expressed concern that our proposed rule was significantly more onerous than the liquidity requirements imposed on commercial banks.
Our new regulation incorporates many of the principles that the Basel Committee and the Federal banking agencies have articulated on liquidity management because many of these fundamental concepts apply to all financial institutions, including FCS banks and depository institutions. The comprehensive supervisory approach developed by the Basel Committee and the Federal banking agencies effectively strengthens both the liquidity reserves and the liquidity risk management practices at regulated financial institutions. The most important features of the framework of other regulators that we adopted pertain to: (1) A multi-tiered approach to the liquidity reserve that requires FCS banks to keep a sufficient amount of cash and highly liquid investments on hand to pay obligations that fall due in next 15, 30, and 90 days; (2) a supplemental liquidity buffer that provides FCS banks with a stable source of liquidity over a longer period of time; (3) specific policies and internal controls that combat liquidity risk; and (4) contingency funding planning based in part on the results of liquidity stress tests.
This principles-based approach is comprehensive, yet flexible because it applies to all types of financial
As the preamble to the proposed rule explains, and some commenters acknowledge, we tailored these principles and concepts to the System's unique structure and circumstances. Accordingly, we modified the supervisory approach of the Basel Committee and the Federal banking agencies to apply it to the System. As noted above, the FCS is a nationwide network of borrower-owned financial cooperatives that primarily lend to agricultural enterprises in rural areas. Other fundamental differences between the System and depository institutions are: (1) FCS institutions are instrumentalities of the United States and GSEs; (2) their common equity is not publicly traded; (3) the issuance of Systemwide debt securities is the primary source of System funding; and (4) the System has no assured governmental lender of last resort. Generally, the funding sources, asset portfolios, and investment activities of regulated non-System financial institutions are more diversified and complex than those of the FCS. We took all of these factors into account as we developed this new liquidity regulation to meet the unique structure, needs, and circumstances of FCS institutions, and threats they face. Thus, our revised liquidity regulation diverges from the approach of the Basel Committee and the Federal banking agencies when circumstances warrant it.
The commenters asked the FCA not to get ahead of the other regulators in implementing the concepts of Basel III. This request seems to reflect System concerns that our new liquidity regulation will become effective before Basel III.
Basel III is not the only basis for the new liquidity regulation. The revised regulation also builds upon the System's own initiatives to improve liquidity management as well as the FCA's experiences from examining liquidity risk management at Farm Credit banks and the Funding Corporation. In this context, the new regulation implements the best practices for liquidity management at FCS banks, and there is no reason for the FCA to delay implementation until Basel III is fully implemented at other financial institutions. Of course, the FCA will closely monitor how the Federal banking agencies adjust Basel III and apply it to the institutions they supervise. As always, the FCA has authority to further amend § 615.5134, or take other appropriate actions concerning liquidity at FCS banks in response to external developments, including changes to the Basel III framework.
Some commenters allege that our new regulatory approach to liquidity is “too detailed and prescriptive compared to the principles-based approach” of the other regulators. Yet, we observe that our new regulation follows the core concepts of the principles-based approach of the other regulators by requiring FCS banks to: (1) Retain an adequate stockpile of high-quality liquid assets to cover the next 15, 30, and 90 days; (2) maintain supplemental liquidity over a longer timeframe; (3) improve liquidity risk management practices; and (4) and enhance contingency funding planning. These requirements will put FCS banks in a stronger position to endure and outlast future crises that could impede their access to funding. Although the commenters may view this approach as “too detailed and prescriptive,” it is essential from a safety and soundness perspective.
We received two comments about how the new liquidity regulation may adversely affect the ability of System banks to issue short-term discount notes to fund their operations when financial markets are in turmoil. These commenters assert that discount notes are a strong source of System liquidity during times of crisis. From the commenters' perspective, GSE status enables FCS banks to sell discount notes to investors, who seek high-quality investments during times of market turmoil. The commenters ask the FCA to recognize the liquidity that discount notes provide the FCS during times of market upheaval, and avoid promulgating an inflexible rule that compel System banks to lengthen the maturity of their liabilities and hold more low-yielding liquid assets. The commenters expressed concern that the proposed rule would significantly curtail the issuance of discount notes, which in turn, would raise the costs to the System's customer-owners.
Discount notes are one of many tools that System banks have at their disposal to mitigate liquidity risk. The FCA expects FCS banks to develop balanced and flexible strategies that they can utilize under different scenarios, especially when economic and financial conditions rapidly change. System banks should not become overly dependent on discount notes.
Although discount notes performed well in the last financial crisis, their effectiveness is much less certain when the agricultural sector or the FCS is experiencing significant stress. For example, during the agricultural credit crisis of the mid-1980s, investors demanded high risk premiums on all System debt obligations, including short-term instruments.
By encouraging System banks to diversify their repayment sources for maturing debt, the FCA's regulatory approach enhances safety and soundness. FCS banks face potential refunding risks when they replace maturing debt with new debt issuances especially, very short-term discount notes. If market conditions rapidly deteriorate, investors may demand exorbitant premiums for purchasing System debt securities, and/or FCS banks may find few buyers for their Systemwide securities. Including more high-quality liquid assets in their liquidity reserves is a prudent practice because it helps System banks mitigate these potential refunding risks.
Discount notes are currently in high demand primarily because of the System's strong financial condition and its GSE status. As a result, discount notes are an inexpensive source of funding for the FCS, which can help offset the costs that System banks incur
For all these reasons, the final rule is likely to lessen System overall usage of discount notes, but it should not significantly affect the program.
In contrast to depository institutions and other financial institutions, the FCS lacks an assured governmental lender of last resort that could inject liquidity into System banks during times of prolonged paralysis in financial markets. Some commenters encouraged the FCA to accelerate its efforts to find an assured lender of last resort for FCS banks so they will have an emergency source of liquidity if their access to the market becomes impeded.
The FCA and Farm Credit System Insurance Corporation (FCSIC) have undertaken efforts to establish an emergency source of liquidity for the System. These efforts, however, are separate from the FCA's supervision and regulation of liquidity risk management at FCS banks. In the absence of an assured governmental lender of last resort, System banks must maintain sufficient liquidity to absorb the impact of market disruptions and economic downturns. Through FCA's effective regulation and supervision of the System, the System banks are able to assure investors that they have adequate liquidity to meet their obligations, even though they have no assured lender of last resort.
Two passages in the preamble to the proposed rule addressed the relationship between investments held for liquidity and the System's GSE status.
These preamble statements generated comments from the Council and one FCS bank. Both commenters interpret our preamble statements as suggesting that GSE status prohibits System banks from generating positive earnings from their liquidity reserves and supplemental liquidity buffers. These commenters claim that these statements indicate that the FCA expects System banks to either lose money or break even on their liquidity portfolios. One commenter asserts that nothing in the Farm Credit Act of 1971, as amended (Act) supports the conclusion that the System's GSE status means that investments cannot generate profits, or at a minimum, cover funding costs. Both commenters claim the proposed rules for Farmer Mac specifically recognize income generation as a legitimate investment purpose and allow Farmer Mac to hold profitable assets in its liquidity reserve and supplemental liquidity buffer. As result, the commenters ask the FCA to provide flexibility so FCS banks can also manage their liquidity portfolios “in a manner to generate reasonable long-term returns and minimize the cost of liquidity management.”
The FCA reiterates its longstanding position that System banks are GSEs and, therefore, the
Maintaining an adequate stock of high quality liquid assets that can withstand turbulence in the markets often means that System banks must forego higher earnings on certain investments. The highest quality liquid assets can be easily and quickly converted into cash at little or no loss compared to book value. For this reason, highly liquid investments entail less risk and, therefore, they tend to generate lower earnings. Higher earning investments, such as certain mortgage-backed securities (MBS), often proved unsuitable as a backup source of liquidity during the 2008 crisis.
The Council and a System bank commented that the FCA treats Farmer Mac more leniently than FCS banks. According to these commenters, the FCA is imposing more onerous liquidity requirements on System banks than Farmer Mac, and it is encouraging Farmer Mac to generate earnings from investments while discouraging FCS banks from doing so.
The Council raised these issues when it commented on the investment management rules for System banks and Farmer Mac, and we responded to these concerns in the preambles to the final rules.
In response to the comments, the FCA has restructured and consolidated the final regulation. The nine main provisions of the proposed rule have been reduced to six in the final rule. The FCA combined proposed §§ 615.5134(b), 615.5134(e), and 615.5134(g) into a single provision, final § 615.5134(b), which now: (1) Establishes the liquidity reserve requirement for all FCS banks; (2) addresses the composition of the liquidity reserve; and (3) specifies the discounts for assets held in the liquidity reserve. We have also deleted the FCA's reservation of authority in proposed § 615.5134(i) from the final regulation. Many of the individual provisions of the
The cornerstone of effective liquidity management at each FCS bank is its liquidity policy, which the board of directors adopts and management implements. Existing § 615.5133(c) requires FCS banks to adopt a liquidity policy. However, the only affirmative requirement that it imposes is that bank policies describe the liquidity characteristics of eligible investments that each Farm Credit bank holds to meet its liquidity needs and institutional objectives. The FCA proposed adding a new paragraph to the liquidity regulation, § 615.5134(a), that for the first time would require Farm Credit banks to address specific issues in their liquidity policies. Proposed § 615.5134(a)(1) focused on the responsibilities of the bank's board of directors while proposed § 615.5134(a)(2) specified seven issues that bank policies must address.
Proposed § 615.5134(a)(1) would require the board of directors of each FCS bank to adopt a written liquidity policy, which must be compatible with the bank's investment management policies under § 615.5133. The preamble to the proposed rule stated that the FCA expects the bank's liquidity policy to fit into its overall investment strategy because effective liquidity risk management is critically important to the bank's long-term viability.
The Council commented on proposed § 615.5134(a)(1). These comments focused on the proper roles and responsibilities of the board of directors and senior management in developing and executing the bank's strategies for containing liquidity risk. The Council indicated that the FCA failed to recognize that boards of directors and senior management play different roles in developing, approving, and applying policies, strategies, and procedures. From the commenter's perspective, the proposed rule seems to require boards to develop and adopt liquidity strategies and policies, rather than clearly articulating an appropriate risk tolerance level for the bank. The commenter also asserted that it is the responsibility of senior management to develop strategy, policies, and procedures to manage liquidity, which the board then reviews and approves. Finally, the commenter claims that the FCA's approach about the respective roles of boards of directors and senior management on liquidity policy is the opposite of guidance from the Federal banking agencies.
The FCA responds that the board of directors is ultimately responsible for ensuring that the bank always maintains sufficient liquidity so it can pay maturing obligations and fund its operations. The board discharges this responsibility by adopting policies, procedures, and parameters for monitoring, measuring, managing, and mitigating liquidity risk to the bank. More specifically, the board articulates risk tolerance levels, internal controls, and other limits in its policies, while senior management operates within those parameters as it carries out the board's policy. Contrary to the commenters' claims, the plain language of § 615.5134(a)(1) recognizes that the board of directors and senior management have distinct roles and separate powers in protecting the bank's liquidity. In fact, the preamble to the proposed rule acknowledged that senior management, not the board of directors, develops and implements strategies for managing liquidity risk on a day-to-day basis.
The Council suggested a technical revision to the third sentence of proposed § 615.5134(a)(1), which would require the board to review its liquidity policy at least once a year, and “affirmatively validate” its sufficiency, and make any revision it deems necessary. The commenter advised us that FCS banks are uncertain about how boards of directors are supposed to “affirmatively” validate the sufficiency of the bank's liquidity policy. The commenter also expressed concern that the word “affirmatively” creates unnecessary regulatory uncertainty because it is a vague requirement and is, therefore, subject to varying interpretations over time. For these reasons, the commenter asked us to drop the term “affirmatively” from § 615.5134(a)(1), and bring it more in line with the approach of the Federal banking agencies.
The commenter has persuaded us that this provision of proposed § 615.5134(a)(1) is vague and susceptible to different interpretations. Boards of directors at Farm Credit banks should clearly understand exactly what § 615.5134(a)(1) requires them to do. For this reason, we have deleted the phrase “affirmatively validate” from the third sentence of § 615.5134(a)(1), and replaced it with the word “assess.” Final 615.5134(a)(1) now requires the board of directors of each FCS bank, at least once a year, to: (1) Review its liquidity policy; (2) assess the sufficiency of this policy; and (3)make any revisions to the liquidity policy that it deems necessary. This amendment also addresses the commenters' substantive concerns by more clearly differentiating the roles and responsibilities of the board and senior management. By assessing the sufficiency of the liquidity policy, the board evaluates whether senior management has effectively monitored, measured, managed, and mitigated liquidity risk in accordance with the board's existing policy.
Proposed § 615.5134(a)(2) focused on the content of the board's liquidity policies. This regulatory provision identifies seven different issues that a Farm Credit bank, at a minimum, must address in its liquidity policies. As noted in the preamble to the proposed rule, the policies of each FCS bank should be comprehensive and commensurate with the complexities of the bank's operations and its risk profile.
Proposed § 615.5134(a)(2) elicited comments from the Council and all four Farm Credit banks. These comments ranged from general statements about the effects that § 615.5134(a)(2) would have on liquidity management at FCS banks to detailed critiques and recommendations about each clause of this provision. All five commenters
Several commenters expressed concern that § 615.5134(a)(2) would inhibit the banks' ability to effectively manage their liquidity and investments. We received comments that proposed § 615.5134(a)(2), when combined with the new investment management regulation, create a complex layering of regulatory requirements that are both duplicative and unduly burdensome to the banks. The Council commented that our regulation would hamper the banks from taking an integrated risk management approach to investments and liquidity. By detailing what a policy must contain, this commenter claimed that FCA inappropriately interfered with the discretion of the board to direct and oversee liquidity management at the bank.
The FCA declines the System's request to replace § 615.5134(a)(2) with a regulatory provision that is general in nature. This provision is a vital component of FCA's new regulation because it strengthens liquidity risk management practices at FCS banks. By requiring board policies to address specific core issues, the regulation instills greater discipline in liquidity risk management practices that will better enable System banks to outlast adverse economic, financial, and market conditions under differing circumstances and scenarios. Rather than interfering with the discretion of the board to direct and oversee liquidity management at the bank, § 615.5134(a)(2) requires board policies, at a minimum, to focus on those basic core components of liquidity risk management that are crucial to the bank's safety and soundness.
This regulation does not prevent System banks from adopting an integrated risk management approach to liquidity and investments. In fact, prudent risk management requires financial institutions to simultaneously monitor, manage, and mitigate risks to individual assets, various portfolios, and the entire institution. Our regulation requires boards to specifically address liquidity risk as part of their efforts to manage the bank's investments. Nor is this provision duplicative of our investment management regulation because it states that board policies must describe how assets in the liquidity reserve or supplemental liquidity buffer would enable the bank to continue funding its operations if market access is impeded.
One bank commented that our approach compels System banks to engage in management practices that focus on regulatory compliance rather than sound liquidity management. The FCA disagrees with the commenter. No conflict exists between compliance with this regulation and sound liquidity management practices at System banks. To the contrary, regulatory compliance works in tandem with sound and disciplined liquidity management practices at financial institutions. In fact, sound management practices already in place at System banks influenced us as we developed this regulatory requirement.
The Council, on behalf of System banks, offered comments and suggestions about each of the seven different issues that proposed § 615.5134(a)(2) requires every FCS bank to address, at a minimum, in its liquidity policy. As explained in greater detail below, we revised § 615.5134(a)(2)(i) by reducing the number of issues that the board's policy must address from seven to five. Additionally, we modified some of the provisions in § 615.5134(a)(2) to address the commenters' concerns. However, we also retained other provisions of proposed § 615.5134(a)(2) without revision.
Proposed § 615.5134(a)(2)(i) would require the bank's policy to address the purpose and objectives of the liquidity reserve. The preamble to the proposed rule stated that this section of the bank's policies should distinguish the purpose and objectives of the liquidity reserve from the other operations and asset-liability functions of the bank, including management of interest rate risk.
The Council commented that proposed § 615.5134(a)(2)(i) addresses a “superfluous and self-evident matter” that needs no regulation. The commenter also took issue with our position that the board's liquidity policy should distinguish liquidity management from asset-liability management by stating that there is no reason why any bank would confuse the two.
The commenter has not persuaded us to omit § 615.5134(a)(2)(i) from the final rule. Our reasons for incorporating this provision into the revised liquidity rule remain valid and, therefore, we adopt § 615.5134(a)(1)(i) as a final regulation without change. This provision does not add a new regulatory requirement for FCS banks. Since 1993, our investment management regulation at § 615.5133 has required the boards of Farm Credit banks to adopt written policies that address the purpose and objectives of the banks' investments, including those held for liquidity.
Adding a provision to the liquidity regulation that specifically requires bank boards to address the purpose and objectives of the liquidity reserve in written policies strengthens the System's safety and soundness by instilling greater discipline in the liquidity risk management practices at System banks. An integrated approach to all aspects of asset-liability management is crucial to safety and soundness, and in this context, System liquidity reserves must be adequately stocked so each bank can pay its debts and fund its operations when deteriorating economic and financial conditions obstruct market access. The goal of § 615.5134(a)(2)(i) is to prompt boards and senior management to more carefully consider how various types of prospective investments help counteract liquidity risk to their banks. A policy that specifically focuses on the purpose and objectives of the liquidity reserves will guide each bank to select a proper mix of high-quality liquid assets that will counteract liquidity risk to the bank based on the complexity of its operations and its risk tolerance level. In addition to their liquidity reserves, System banks may hold other eligible investments for the purposes of managing interest rate risks and investing surplus short-term funds.
The commenter also disputed our preamble statements that the liquidity reserve is primarily an emergency source of funding. We already responded to this particular comment earlier in the discussion above about GSE status.
Proposed § 615.5134(a)(2)(ii) would require the board's liquidity policy to
The FCA received comments about proposed § 615.5134(a)(2)(ii) from the Council and a System bank. The Council found this requirement redundant to the diversification requirement in the investment management rule. The commenter asked the FCA to omit § 615.5134(a)(2)(ii) from the final rule, because it “is unnecessary and * * * creates a complex and confusing layering of the regulatory requirements in the investment area.”
The FCA retains § 615.5134(a)(2)(ii) as a provision in the final rule without revision. Diversification of the liquidity portfolios at Farm Credit banks is essential to the System's overall safety and soundness, especially because the FCS is a GSE that finances primarily the agricultural sector of the economy and it currently has no assured governmental lender of last resort. The liquidity portfolio serves a different function than other segments of the investment portfolio that the bank relies on for other asset-liability risk management purposes. The 90-day liquidity reserve, for example, should be comprised of cash and high quality, shorter-term, and consequently lower-yielding liquid investments, whereas these kinds of assets may not necessarily be suitable for other investment purposes. For this reason, the FCA expects bank policies to focus on, and specifically address diversification of the liquidity portfolio separately from the diversification of other segments of the investment portfolio.
A Farm Credit bank commented on a preamble passage, which stated that the policy must: (1) Address the desired mix of cash and investments that FCS banks should hold under a variety of scenarios; and (2) establish criteria for diversifying assets based on issuers, maturities, and other relevant factors. The commenter stated that these sorts of specific matter can and do change daily, which requires management to quickly respond. From the commenter's perspective, § 615.5134(a)(2)(ii) should not require boards to embed such specific details into a policy that cannot be quickly changed as an adverse scenario unfolds. In the commenter's opinion, this regulatory diversification requirement eliminates senior management's ability to exercise discretion and judgment to respond to a looming threat to the bank's liquidity. This commenter also perceives this and other provisions of proposed § 615.5134(a)(2) as inappropriately blurring the board's responsibilities to set policy parameters with senior management's duty to establish best practices and operational procedures for day-to-day operations.
The FCA responds that this provision requires the board to establish general parameters about diversification. Senior management works within the confines of the board's policy. Senior management should have the opportunity to provide input as the board develops its diversification policy for the bank's liquidity portfolio. This input should result in a diversification policy that enables senior management to adjust the composition of the liquidity portfolio as part of its daily operation of the bank in accordance with board policy.
Proposed § 615.5134(a)(2)(iii) would require board policies to establish maturity limits and credit quality standards for investments that the bank holds in its liquidity reserves. The preamble to the proposed rule explained this aspect of the bank's policies would help management to target and match cash inflows from loans and investments to outflows needed to pay its maturing obligations.
The FCA received a comment about proposed § 615.5134(a)(2)(iii) from the Council. The commenter agrees that the liquidity policy needs to address the composition of investments that System banks hold in their liquidity reserve. However, the commenter asked us to delete this provision from the final rule because the provisions of § 615.5134(b), which pertain to different levels of the liquidity reserve, already addresses this issue with sufficient specificity. The FCA is persuaded by this comment, and it omits this provision from the final regulation.
The preamble to proposed § 615.5134(a)(2)(iii) discussed the credit quality standards for investments held in the bank's liquidity portfolio. According to the preamble, FCS banks may consider the credit ratings issued by a Nationally Recognized Statistical Rating Organization (NRSRO) when it determines the credit quality of a security, but it may not rely solely or disproportionally on such ratings. The FCA also asked for comments on approaches concerning creditworthiness standards for investments. The Council commented that the System appreciated the FCA's position on this issue, and referred us to its comments on this issue in previous rulemakings pertaining to investment management and capital. The FCA plans to address how FCS institutions should use external credit ratings to assess the credit quality of securities in these other rulemakings.
Under proposed § 615.5134(a)(2)(iv), the board's policy should cover the target number of days of liquidity that the bank needs, based on its business model and risk profile. Estimating the target number of days of liquidity that the bank will need to outlast various stress events is an effective tool for managing and mitigating liquidity risks.
The FCA received a comment about proposed § 615.5134(a)(2)(iv) from the Council. The commenter agreed with this regulatory provision because it concurred that the days of liquidity target is an appropriate and logical risk tolerance measure that boards should include in their banks' policies. The FCA retains proposed
Proposed § 615.5134(a)(2)(v) would require bank policies to address the elements of the CFP in proposed § 615.5134(h). The CFP addresses unexpected events or unusual business conditions that increase liquidity risk at Farm Credit banks. One of the objectives of the proposed rule is to strengthen contingency funding planning at System banks. According to the preamble to proposed § 615.5134(a)(v), an effective CFP would cover at a minimum: (1) Strategies, policies, and procedures to manage a range of stress scenarios; (2) chains of communications and responsibility within the bank; and (3) implementation of the CFP during all phases of an adverse liquidity event.
The Council and a System bank submitted comment letters opposing this provision. Both commenters encouraged us to delete this provision from the final rule. The commenters stated that when proposed § 615.5134(a)(v) is read literally, it seems to require the bank board to incorporate the entire CFP into its written policy. They advised us that the regulation should not require banks to document detailed operational procedures for the CFP in their policies. The bank pointed out that management may need to make practical operational changes that would have no significant impact on safety and soundness of the overall CFP. However, any such changes could require board approval if such procedures for the CFP are part of the policy. Accordingly, the commenters advised us that a more prudent approach is to require FCS banks to develop an effective CFP consistent with this regulation.
The FCA agrees with the commenters that it is impractical and burdensome to require the board to incorporate the entire CFP into its written policy. Additionally, incorporation of the CFP into the board's policy could limit management's ability to dynamically modify the CFP as conditions change. For these reasons, the FCA omits § 615.5134(a)(2)(v) from the final regulation.
Proposed § 615.5134(a)(2)(vi) would require the board's policy to address delegations of authority pertaining to the liquidity reserves.
The FCA received no comment about this regulatory provision. Accordingly, we adopt it as final § 615.5134(a)(2)(iv) without revision.
The final provision of proposed § 615.5134(a)(2) would require the board's policy to address reporting requirements, which at a minimum would require management to report to the board at least once every quarter about compliance with the bank's liquidity policy and the performance of the liquidity reserve portfolio. This provision would also require management to report any deviation from the bank's liquidity policy, or failure to meet the board's liquidity targets immediately to the board. The purpose of this provision is to ensure that an effective reporting process is in place, and management communicates accurate and timely information to the board about the level and sources of the bank's exposure to liquidity risk. These reports should enable the board to take prompt corrective action if any problems arise. The FCA expects the board to consider these quarterly reports when it conducts its annual review of the bank's liquidity policy and decides whether to make any revisions pursuant to § 615.5134(a)(1).
The Council commented on proposed § 615.5134(a)(2)(vii). Although the commenter agreed that a quarterly reporting requirement is prudent, it advised us that the requirement that senior management “immediately report” any deviation from the bank's policy or any failure to meet the liquidity targets was unworkable. The commenter asked us to clarify what level of deviation or failure would require senior management to “immediately” report to the board. The commenter also asked to quantify “immediately.”
The FCA redesignates proposed § 615.5134(a)(2)(vii) as final § 615.5134(a)(v). We have also revised this provision to address the commenter's concerns. The first sentence of this provision remains unchanged. As such, the board's policy must require management to report to the board at least once every quarter about compliance with the bank's liquidity policy and the performance of the liquidity reserve portfolio. However, the FCA has amended the second sentence of this provision to require management to report any deviation from the bank's liquidity policy, or failure to meet the board's liquidity targets, to the board before the end of the quarter if such deviation or failure has the potential to cause material loss to the bank. This revision, which is self-explanatory, addresses the commenter's concern by requiring early reporting of deviations or failures that threaten the bank's liquidity or viability.
The proposed rule contained three separate provisions that established a liquidity reserve requirement, addressed the composition of the liquidity reserve, and specified discounts for assets held in the liquidity reserve. More specifically, proposed § 615.5134(b) articulated the core liquidity reserve requirement for FCS banks, while proposed § 615.5134(e) governed the composition of the liquidity reserve, and proposed § 615.5134(g) specified the discounts for the different assets in bank liquidity reserve. We organized proposed § 615.5134(e) in a table format, while the other two provision were expressed in text.
The Council asked us to incorporate the discount table in the preamble to the proposed rule into the text of the final regulation. The commenter suggested that the table “would be a superior and cleaner approach than the wording of the proposed regulation text.” In accepting the commenter's advice, we decided to incorporate the discount table into final § 615.5134(b), rather than keeping it as a free-standing regulatory provision. As we reorganized and restructured the regulation, we realized that the final rule would be easier to read, understand, and implement if we also merged proposed § 615.5134(e) into final § 615.5134(b). We received no substantive comments about the specific discount percentages in proposed § 615.5134(g). Accordingly, we incorporate them into final § 615.5134(b) without amendment.
Proposed § 615.5134(b) would require each Farm Credit bank to maintain at all times a liquidity reserve sufficient to fund at least 90 days of the principal portion of maturing obligations and other borrowing of the bank. The Council and a System bank supported this provision. Accordingly, the FCA is retaining this core requirement as the first sentence of final § 615.5134(b) with one minor, stylistic revision.
The second sentence of proposed § 615.5134(b) would require each System bank to maintain a supplemental liquidity buffer in accordance with proposed § 615.5134(f). As part of our restructuring and reorganization of the final liquidity regulation, this sentence has been removed from final § 615.5134(b), although final § 615.5134(e) still requires all Farm Credit banks to maintain a supplemental liquidity buffer. We received several substantive comments about the supplemental liquidity buffer, which we will address below in the preamble to final § 615.5134(e).
The third sentence of proposed § 615.5134(b) would require FCS banks to discount liquid assets in accordance with proposed § 615.5134(g). As addressed above, we have incorporated proposed § 615.5134(g) into final § 615.5134(b) without substantive revision.
The final sentence of proposed § 615.5134(b) states that the liquidity reserve must be comprised only of cash, including cash due from traded but not yet settled debt, and qualified eligible investments under § 615.5140 that are unencumbered and marketable under proposed § 615.5134(c) and (d). Both the existing and proposed regulations specify that the liquidity reserve must be comprised of cash, including cash due from traded but not yet settled debt, and qualified eligible investments under § 615.5140. We received no comment about this requirement.
The final sentence of proposed § 615.5134(b) differs from the existing rule in that it requires all investments held in the liquidity reserve to be marketable under proposed § 615.5134(d). The FCA received several comments about our definition of “marketability” in proposed § 615.5134(d), and how this definition applied to the bank's liquidity assets in different situations. The FCA responded to the commenters' concerns by adjusting the definition of “marketable” in final § 615.5134(d), and discussing their concerns in the appropriate preamble section below.
Proposed § 615.5134(e) addressed the composition of the liquidity reserve. The first two sentences of the proposed rule contained cross-references to proposed § 615.5134(b) and (e). The FCA has omitted these cross-references from the final rule because they are superfluous now that the FCA has combined all three paragraphs into a single provision.
More substantively, the FCA proposed for the first time to divide the 90-day liquidity reserve into two levels. Under our original proposal, the first level of the liquidity reserve would provide the bank with sufficient liquidity to pay its obligations and continue operations for 30 days if market access became partially or fully impeded during a national security emergency, a natural disaster, or intense economic or financial turmoil. The proposed rule would require FCS banks to use the instruments in the first level of the liquidity reserve to meet obligations that mature starting on day 1 through day 30. Additionally, the proposed rule would mandate that cash and certain instruments with a final maturity of 3 years or less comprise at least 15 days of the first level of the liquidity reserve. The 15-day sublevel would provide the bank with enough cash and short-term, highly liquid assets so it could pay its obligations and fund its operations for 15 consecutive days during an emergency when the debt markets are closed, or the System's funding costs become untenable.
Final § 615.5134(b) divides the liquidity reserve into three levels. This revision is part of our efforts to restructure and reorganize this provision so it is easier to read, understand, and apply, as the commenters requested. However, this revision is not substantive. Under final § 615.5134(b), the first level of the liquidity reserve covers obligations that mature on days 1 through 15. Similarly, level 2 applies to days 16 through 30, while level 3 covers days 31 through 90. This revision improves the clarity of the regulation by more clearly communicating: (1) The exact period of time each level of the liquidity reserve covers; and (2) which assets a bank may hold in each level.
The table in proposed § 615.5134(e) identified the assets that would comprise Level 1 of the bank's liquidity reserve. All of these assets are highly liquid because they are either cash, or investments that are high quality, close to their maturity, and marketable. Under the proposed rule, Farm Credit banks could hold the following assets in Level 1 of their liquidity reserve:
• Cash (including cash balances on hand, cash due from traded but not yet settled debt, insured deposits held at federally insured depository institutions in the United States;
• United States Treasury securities that have final maturities and other characteristics that would best enable the bank to fund operations if market access becomes obstructed;
• Other
• MBS issued by the Government National Mortgage Association (Ginnie Mae);
• Senior debt securities of Government-sponsored agencies that mature within 60 days, excluding the debt securities of FCS banks and Farmer Mac; and
• Diversified investment funds that are comprised exclusively of Level 1 instruments.
Under the proposed rule, the second level of the liquidity reserve would provide System banks with sufficient liquidity to fund their obligations and continue operations for the next 60 days (days 31 through 90). Under proposed § 615.5134(e), FCS banks would hold Level 2 assets to mitigate liquidity risks associated with a prolonged stress event. Level 2 investments would include:
• Additional amounts of Level 1 investments;
• Government-sponsored agency senior debt obligations with maturities that exceed 60 days, excluding FCS debt securities;
• Government-sponsored agency MBS; and
• Diversified investment funds that are comprised exclusively of Levels 1 and 2 instruments.
The FCA received no comments that opposed the assets that the proposed rule designated for the liquidity reserve. Under final and redesignated § 615.5134(b), Level 1 assets are:
• Cash (including cash balances on hand, cash due from traded but not yet settled debt, insured deposits held at federally insured depository institutions in the United States;
• Overnight money market instruments;
• Obligations of the United States with a final remaining maturity of 3 years or less;
• Senior debt securities of Government-sponsored agencies that mature within 60 days, excluding the debt securities of FCS banks and Farmer Mac; and
• Diversified investment funds that are comprised exclusively of Level 1 instruments.
In the proposed rule, we inadvertently excluded overnight money market investments from the list of highly liquid assets that FCS banks could hold in the first 15 days of their liquidity reserve. Overnight money market investments are promptly convertible into cash at their face value, and as their name implies, they mature overnight. As a result, these assets have characteristics that are similar to cash. Adding overnight money market investments to the list of assets that FCS banks are authorized to hold in Level 1 of the liquidity reserve should raise no objection or controversy. It is a standard practice of financial institutions to hold overnight money market investments for liquidity. For this reason, we have included these instruments in the list of highly liquid assets that FCS banks are authorized to hold in their liquidity reserve.
Under the final rule, the following assets qualify for Level 2 of the liquidity reserve:
• Additional Level 1 instruments;
• Obligations of the United States with a final remaining maturity of more than 3 years;
• MBS that are backed by the full faith and credit of the United States as to the timely repayment of principal and interest; and
• Diversified investment funds comprised exclusively of Level 1 and Level 2 instruments.
Under the final rule, Level 3 assets are:
• Additional Level 1 and Level 2 instruments;
• Government-sponsored agency senior debt securities with maturities exceeding 60 days, excluding the senior debt securities of FCS banks and Farmer Mac;
• Government-sponsored agency MBS that the timely repayment of principal and interest is not explicitly backed by the full faith and credit of the United States;
• Money market instruments maturing within 90 days; and
• Diversified investment funds comprised exclusively of Levels 1, 2, and 3 instruments.
The Council and two Farm Credit banks submitted substantive comments about concerns they had with three policy positions that the FCA articulated in the preamble to proposed § 615.5134(e). Only one of these concerns necessitates an adjustment to the regulation. We respond to the two other issues below.
One FCS bank acknowledged that proposed § 615.5134(e) was remarkably close to the practices that FCS banks already follow. According to the commenter, System banks voluntarily maintain 15 days of “pristine” liquidity, followed by a sufficient amount of high quality assets that provide liquidity for the next 60 days. Beyond that, FCS banks comply with current regulatory minimum of 90 days of liquidity with other investments. The commenter pointed out that all Farm Credit banks have voluntarily agreed to hold at least 120 days of liquidity.
However, this bank along with the Council commented that proposed § 615.5134(e) introduces greater complexity and burden to liquidity management in a way that does not strengthen the liquidity of any FCS bank. The commenters illustrated the System's concern by pointing to a passage in the preamble to the proposed rule which stated that FCS banks would first draw on the 15-day sublevel in the event of significant stress. The commenters advised us that drawing down instruments in the 15 days of “pristine” instruments may not necessarily be the best approach for a bank to take in certain scenarios. According to the commenters, the bank may anticipate more difficult market conditions in the future and, therefore, it may decide that a more prudent approach is to continue holding its most “pristine” liquid assets in place. Thereby, other factors may favor the sale of the least “pristine” liquid assets first. The commenters expressed concern that our interpretation of proposed § 615.5134(e) would deny System banks the flexibility to determine which assets in the liquidity reserve to draw upon first during a crisis.
The commenters' concerns have merit. The FCA confirms that final § 615.5134(b) does not prescribe which assets in the liquidity reserve a System bank must draw upon first during a crisis. Instead, the final rule will leave this matter to the discretion of the bank. Changes to the text and format of § 615.5134(b) clarify that the final regulation does not require FCS banks to liquidate their most “pristine” liquid assets first during times of market stress. Additionally, language in the proposed rule that would have required FCS banks to “sequentially apply” specific instruments to obligations that mature within specified timeframes has been omitted from the final rule. Finally, the FCA modified the text of the provision so it requires each Farm Credit bank to structure its liquidity reserve so that it has sufficient assets of various calibers to meet obligations that mature within each of the specified timeframes. These changes signal that each bank has discretion to liquidate assets in whatever order that best serves its interests as it responds to mounting distress in the markets.
Next, the Council asked us to clarify a passage in the preamble which stated that “each FCS bank must document and be able to demonstrate to FCA examiners how its liquidity reserve mitigates the liquidity risk posed by the bank's business mix, balance sheet structure, cash flows, and on-and-off balance sheet obligations.” The commenter wanted to know if this preamble statement signals that the FCA is increasing documentation requirements on FCS banks, and subjecting their liquidity practices to more stringent examination. After noting that FCS banks currently document and demonstrate compliance with our liquidity regulations to FCA examiners, the commenter requested that FCA examiners maintain open lines of communication with the directors and senior managers of System banks instead of making examinations of liquidity more rigorous.
The FCA responds that the commenter is misconstruing the preamble passage. The commenter is referring to a broader preamble passage which verified that proposed § 615.5134(e) would allow each FCS bank to exceed the
The preamble passage in question reaffirms the FCA's longstanding position that each FCS bank must be able to demonstrate to FCA examiners how its liquidity reserves mitigate the liquidity risk posed by the bank's business mix, balance sheet structure, cash flows, and on- and off-balance sheet obligations. This preamble statement does not signal that the FCA is changing its approach to examining liquidity at System banks, or that such examinations will now become confrontational. Instead, it indicates how the FCA will apply its longstanding examination approach to the new liquidity regulation.
The Council and a Farm Credit bank commented about the role that MBS and collateralized mortgage obligations (CMOs) issued or guaranteed by a Government agency or a Government-sponsored agency
These two commenters want the final rule to authorize Farm Credit banks to hold MBS and CMOs issued or guaranteed by Ginnie Mae and the two Government-sponsored agencies in both Levels 1 and 2 of their liquidity reserves because these instruments, in their opinion, are inherently liquid and marketable. The commenters asked us to explicitly recognize that such investments are consistent with the definition of “marketable” in § 615.5134(d) because of the ease and certainty of their valuation. The commenters contend that the FCA is more restrictive than the Board of Governors for the Federal Reserve System, which proposed to allow systemically important financial institutions (SIFIs) to include unencumbered government and agency guaranteed MBS and CMO in their 30-day liquidity reserves.
These comments appear to be based on a passage in another section of the preamble which stated that the regulation, in practice, effectively excludes structured investments from the liquidity reserve at FCS banks, although banks could hold these assets in their supplemental liquidity buffer.
Our regulatory approach towards the MBS of Ginnie Mae, Fannie Mae, and Freddie Mac is rooted in safety and soundness considerations. A diverse selection of MBS instruments is available in the markets, each exhibiting different credit, prepayment, and other risks. As a result of the risk factors, many of these instruments are less suitable for the higher levels of the liquidity reserve although they may generate more earnings for the bank. The 2008 crisis illustrated the limitations of MBS as a liquidity backstop.
For these reasons, the FCA's regulatory approach assigns different categories of MBS to different levels of the liquidity reserve based on their liquidity characteristics. Final § 615.5134(b) excludes MBS from the first level of the liquidity reserve (days 1 through 15) because they lack the liquidity characteristics of cash, overnight money market instruments, United States Treasuries with a final remaining maturity of 3 years or less, or the senior debt securities of Government-sponsored agencies that mature within 60 days. Under the final rule, MBS and CMOs issued or guaranteed by a Government agency or a Government-sponsored agency qualify for either Level 2 or Level 3 of the bank's liquidity reserve. The liquidity characteristics and risk profiles of these Ginnie Mae, Fannie Mae, or Freddie Mac MBS or CMOs determine whether they belong in Level 2 or Level 3 of the liquidity reserve.
The final rule does not treat all MBS and CMOs of government agencies and Government-sponsored agencies equally, as the commenters requested. As discussed above, Ginnie Mae, Fannie Mae, and Freddie Mac offer a diverse array of MBS, and each exhibits different liquidity characteristics and risk factors. The final rule recognizes these differences by assigning MBS and CMOs issued or guaranteed by Ginnie Mae, Fannie Mae, and Freddie Mac to different levels of the liquidity reserve.
Fannie Mae and Freddie Mac are currently under the conservatorship of the United States Treasury, and their long-term status is uncertain. This complicates the FCA's efforts to devise an approach that balances our safety and soundness concerns with the needs of System banks for flexibility in selecting Ginnie Mae, Fannie Mae, and Freddie Mac MBS for their liquidity reserves. While the ultimate status of Fannie Mae and Freddie Mac is unresolved, the FCA has decided that the full faith and credit of the United States is the standard that determines whether particular MBS or CMOs belong in Level 2 or Level 3 of the bank's liquidity reserve. Under the final rule, MBS that are issued or guaranteed by Ginnie Mae, Fannie Mae, and Freddie Mac qualify for Level 2 of the liquidity reserve if they are explicitly backed by the full and credit of the United States as to the timely payment of principal and interest. Conversely, MBS that are issued or guaranteed by Fannie Mae and Freddie Mac belong in Level 3 of the liquidity reserve if the timely payment of principal and interest are not explicitly backed by the full faith and credit of the United States. The reason the final rule relegates MBS of Government-sponsored agencies that are not explicitly backed by the full faith and credit of the United States to Level 3 of the liquidity reserve is because they could potentially experience reduced marketability during a widespread market crisis.
We are unable to confirm, as the commenter requests, that all Government-sponsored agency MBS are automatically marketable within the meaning of § 615.5134(d). Their “ease and certainty of valuation” depends on whether they exhibit low market risks under stressful conditions. We note that the Federal banking regulators continue to require depository institutions to risk weight the MBS of Fannie Mae and Freddie Mac at 20 percent, while the MBS of Ginnie Mae are risk weighted at zero. Under the circumstances, the FCA does not conclude that Fannie Mae and Freddie Mac MBS have the same low risks and ease of valuation as Ginnie Mae MBS. This is another reason why the final rule does not treat all MBS of government agencies and Government-sponsored agencies the same.
The approach that the Board of Governors of the Federal Reserve System follows for SIFIs is not appropriate for FCS banks in this situation. FCS banks are GSEs that primarily finance a single industry, and they have no assured government lender of last resort. Some FCS banks were vulnerable to an overabundance of MBS of Government-sponsored agencies in their liquidity portfolios during the 2008 crisis. SIFIs are large, diversified, and complex organizations that have a different risk profile than FCS banks. In contrast to SIFIs and federally chartered or federally insured commercial banks, FCS banks do not have assured access to the discount windows at Federal Reserve Banks. Under the circumstances, there is no certainty that the Federal Reserve Banks would extend lines of credit to Farm Credit banks during times of stress and accept MBS as collateral.
The preamble to the proposed rule stated that the FCA was contemplating whether to add a specific provision to the final regulation that would require the liquidity reserve to cover unfunded commitments and other contingent obligations. As the preamble observed, unfunded commitments and other material contingent obligations potentially expose FCS banks to significant safety and soundness risk. Requiring FCS banks to hold sufficient liquidity to cover unfunded commitments and other contingencies would mitigate risks that pose a threat to their liquidity, solvency, and viability, but it could also impose significant burdens and opportunity costs on these System banks. For this reason, we asked the public whether the final rule should explicitly require the liquidity reserve to cover unfunded commitments and other contingency, and if so, under what conditions.
The Council, on behalf of System banks, responded that the FCA should wait until the Federal banking agencies
Currently, existing § 615.5134(b) requires all investments that System banks hold to meet their liquidity reserve requirement to be free of lien. The proposed rule would expand upon this concept by requiring FCS banks to hold only unencumbered assets in their liquidity reserve. Under proposed § 615.5134(c), an asset is unencumbered if it is free of lien and is not explicitly or implicitly pledged to secure, collateralize, or enhance the credit of any transaction. Proposed § 615.5134(c) also would prohibit any FCS bank from using an investment in the liquidity reserve as a hedge against interest rate risk pursuant to § 615.5135 if liquidation of that particular investment would expose the bank to a material risk of loss. As the FCA explained in the preamble to the proposed rule, unencumbered investments are free of the impediments or restrictions that would otherwise curtail the bank's ability to liquidate them to pay its obligations when normal access to the debt market is obstructed.
The FCA received one comment about proposed § 615.5134(c) from the Council. The commenter agreed that investments in the liquidity reserve must be free of lien, and not pledged for any other purpose. However, the commenter opposed the provision in proposed § 615.5134(c) that would prohibit a Farm Credit bank from using an investment in the liquidity reserve as a hedge against interest rate risk pursuant to § 615.5134 if liquidation of the particular investment would expose the bank to a material risk of loss. Besides claiming that “material risk of loss” is an ambiguous standard, the commenter contends that this requirement is “unreasonably limiting and complex.”
The commenter believes that our regulations should grant System banks greater flexibility to use liquid securities for multiple investment purposes. During normal times, securities that Farm Credit banks hold to manage interest rate risk can also provide liquidity without sacrificing the bank's hedge position. For this reason, the commenter claims that securities used to hedge interest rate risk are not diminished from a liquidity perspective. If economic or financial adversity impedes market access, the commenter asserts a System bank could prudently choose to sell a liquid security held as an interest rate hedge so it could raise funds to pay maturing obligations. Finally, the commenter claims that our position is inconsistent with the position of the Federal banking agencies, which only excludes investments from liquidity reserves when they are used to hedge trading assets.
The FCA retains, without revision, the last sentence in final § 615.5134(c), which prohibits a Farm Credit bank from using an unencumbered investment held in its liquidity reserve as a hedge against interest rate risk if liquidation would expose the bank to a material risk of loss. The objective of this regulatory provision is to require System banks to primarily concentrate on counteracting liquidity risks when they select assets for the 90-day liquidity reserve. As discussed elsewhere in this preamble, System banks must stock the liquidity reserve with cash and high-quality liquid securities that are readily convertible into cash at or close to their book value at times when market access becomes impeded. Farm Credit banks dilute the liquidity reserve's capacity to serve as an emergency source of funding when these assets are used for multiple purposes. The purpose of this provision is to ensure that liquidity is the dominant consideration of a System bank when it purchases a security for inclusion in its liquidity reserve. Farm Credit banks may, however, choose investments for the supplemental liquidity buffer that serve the dual purpose of mitigating liquidity risk and hedging interest rate risk.
Moreover, this provision does not ban System banks from hedging interest rate risk with assets held in the liquidity reserve. Instead, it specifically states that an unencumbered investment held in the liquidity reserve cannot be used as a hedge against interest rate risk
The Council claims that a Farm Credit bank could pledge these securities as collateral in a secured borrowing (repo) transaction, rather than liquidating its hedge position. A passage in the commenter's letter states that “when used as collateral, these investments can generate liquidity without loss to the hedge position.”
In response, the FCA notes the repo market for certain types of securities may cease to function during economic or financial crises. In fact, during the 2008 crisis, many financial institutions discovered that they could not pledge many types of securities as collateral in the repo markets although in other circumstances these assets were liquid, marketable, and valuable as collateral. For these reasons, the FCA declines to change its position on this issue.
Finally, we address the Council's comment that our position is inconsistent with the position of the Federal banking agencies, which only excludes investments from liquidity reserves when they are used to hedge trading assets. Farm Credit banks generally hold investments until maturity, rather than trading for profit. As stated above, the final rule allows a System bank to hedge interest rate risk with assets held in the liquidity reserve provided that the hedging activity would not expose the bank to a material risk of loss in a liquidity crisis. Additionally, FCS banks may hold investments that hedge market risks in their supplemental liquidity buffers. From a safety and soundness perspective, the Federal banking agencies' position on this issue is not suitable for the FCS. The FCS is a GSE that lends almost exclusively to a single sector of the economy, it does not take deposits, and it lacks an assured governmental lender of last resort. These reasons justify the FCA's more conservative regulatory approach.
Under our proposal, all eligible investments that a System bank hold in its liquidity reserve must be marketable. Proposed § 615.5134(d) specifies the criteria and attributes that determine
1. Can be easily and immediately converted into cash with little or no loss in value;
2. Exhibits low credit and market risks;
3. Has ease and certainty of valuation; and
4. Can be easily bought or sold.
We received one comment on this section from the Council on behalf of the four System banks. The commenter stated that the four criteria impose “an impossible and unworkably vague standard” and suggested that the FCA adopt an approach that emphasized asset quality rather than marketability. The commenter raised objections to three of the four criteria described above. The commenter did not object to the second criterion, which specifies that a marketable investment displays low market and credit risks.
According to the commenter, the criterion that a marketable investment must be easily and immediately converted into cash with little or no loss in value is particularly problematic. The commenter claims that this criterion lacks specificity because it: (1) Cannot be applied in any consistent manner; and (2) is subject to varying interpretations over time. For this reason, the commenter asked us to revise the first criterion so that § 615.5134(d)(1) simply states that a marketable investment “can be easily converted into cash.” In the commenter's view, this change would allow Farm Credit banks to include more investments in their liquidity reserve after applying the appropriate discount. The commenter believes that its recommended approach is more logical and workable, and consistent with safety and soundness.
The FCA responds that section 4.3(c) of the Act requires Farm Credit banks to pledge certain securities as collateral for the debt obligations they issue. This provision of the Act includes marketable securities approved by the FCA as assets that System banks may pledge as collateral for their borrowings.
A Farm Credit bank should be able to sell any instrument that it holds for liquidity quickly and at close to its book value. The sale of a security for which the fair value and book value diverge significantly can affect capital and earnings to the extent that it exacerbates liquidity risks. Of particular concern is a situation where the sale of an investment held primarily for liquidity results in a significant loss. Such an outcome may mean that a System bank will not generate sufficient revenue from the liquidation of an asset to pay its obligations and fund its assets when it is experiencing significant stress. For this reason, we continue to believe that each System bank must be able to sell any investment held for liquidity purposes with no or minimal effect on its earnings. The commenter's suggestion that the final rule allow investments to qualify for the liquidity reserve if the bank can “easily” convert them into cash at a steep discount from their book value does not address our safety and soundness concerns. In fact, this recommendation would relax an existing safety and soundness standard rather than strengthen it.
However, the commenter's concern that proposed § 615.5134(d)(1) is not susceptible to consistent application and interpretation over time has merit. For this reason, we have changed “immediately” to “quickly” so FCS banks have clearer guidance and greater flexibility about converting liquid assets into cash. We consider “quickly” to mean hours or a few days even during adverse market conditions.
We received no comment about proposed § 615.5134(d)(2), which states that a marketable security exhibits low credit and market risks. This criterion is a vital safety and soundness standard for investments held in System bank's liquidity reserve. Accordingly, we adopt proposed § 615.5134(d)(2) as a final regulation without revision.
The Council asks the FCA whether proposed § 615.5134(d)(3), which would require marketable investments to have ease and certainty of valuation, would exclude structured investments, such as CMOs, particularly those issued by Government-sponsored agencies, from the liquidity reserves at Farm Credit banks. From the commenter's perspective, such a result would be inconsistent with both: (1) The objectives of the liquidity reserve requirement; and (2) with the approach taken by the Basel Committee and the Federal banking agencies.
The commenter's question stems from the preamble to proposed § 615.5134(d)(3), which stated that an instrument has ease and certainty of valuation if the components of its pricing formulation are publicly available. Additionally, the same preamble passage states that the pricing of high-quality liquid assets are usually easy to ascertain because they do not depend significantly on numerous assumptions. For these reasons, the preamble passage stated that proposed § 615.5134(d)(3) would “in practice” exclude most structured investments from System bank liquidity reserves. The preamble noted, however, that certain MBS, such as those issued by Ginnie Mae, are highly marketable under this criterion, and they would qualify for a System bank liquidity reserve.
The FCA responds that § 615.5134(d)(3) does not automatically include or exclude all structured investments, such as CMOs from bank liquidity reserves. Some CMOs have ease and certainty of valuation while others do not. For this reason, the FCA expects each bank to conduct due diligence on CMOs that it is considering for its liquidity reserve, and document its conclusions. Bank management should be able to explain its decision to FCA examiners.
Under proposed § 615.5134(d)(4), the final attribute of a marketable investment is that it can be easily bought or sold. As a general rule, money market instruments are easily bought and sold although they are not traded on a recognized exchange. Otherwise, proposed § 615.5134(d)(4) recognizes securities as “marketable” if they are listed on a developed and recognized exchange market. Listing on a public exchange enhances the transparency of the pricing mechanisms of the investment, which in turn, enhances its marketability and liquidity. An investment also would comply with the requirements of proposed § 615.5134(d)(4) if investors can sell or convert them into cash through repurchase agreements in active and sizeable markets, even in times of stress.
The commenter advised us to reconsider our approach to this requirement. The commenter pointed out that exchanges enhance transparency of the price of stock, but not bonds and other debt obligations. Another concern of the commenter is that references to trading on public exchanges may conflict with guidance for the treatment of investments under FASB Fair Value Classification. For this reason, the commenter asks that we omit the phrase “developed and recognized exchange markets” and reorganize this provision so it aligns with the approach of the Federal banking agencies.
The FCA acknowledges that this comment has merit. For this reason, final § 615.5134(d)(4) will now state that “Except for money market instruments, can be easily bought and sold in active and sizeable markets without significantly affecting prices.” This
The FCA proposed to strengthen liquidity management at Farm Credit banks by introducing the new concept of a supplemental liquidity buffer into this regulation. Proposed § 615.5134(f) would require all Farm Credit banks to establish and maintain a supplemental liquidity buffer that would provide a longer term, stable source of funding beyond the 90-day minimum liquidity reserve. The supplemental liquidity buffer would complement the 90-day minimum liquidity reserve. Whereas the primary purpose of the 90-minimum liquidity reserve is to furnish sufficient short-term funding to survive an immediate crisis, the supplemental liquidity buffer would enable Farm Credit banks to manage and mitigate liquidity risk over a longer time horizon.
Under proposed § 615.5134(f), Farm Credit banks would hold supplemental liquid assets that are specific and commensurate to the risks they face in maintaining stable longer term funding. Besides providing FCS banks with a longer term source of stable funding, each bank could draw on the supplemental liquidity buffer if a heavy demand for funds strains its 90-day minimum liquidity reserve during times of turbulence in the market. This supplemental liquidity buffer provides an additional cushion of liquidity that should enable FCS banks to endure prolonged periods of uncertainty. System banks could also deploy assets in the supplemental liquidity buffer to offset specific risks to liquidity that their boards have identified in their liquidity policies and CFPs.
Proposed § 615.5134(e) contained five provisions. First, as stated above, the proposed rule would require all FCS banks to hold liquid assets in excess of the 90-day minimum in the liquidity reserve. However, the proposed rule does not specify the length of time the supplemental liquidity buffer should cover. Second, proposed § 615.5134(f) states that the supplemental liquidity buffer be comprised of cash and qualified eligible investments listed in § 615.5140. As a result, this regulation would allow FCS banks to hold qualified eligible investments in their supplemental liquidity buffer that they could not hold in their 90-day liquidity reserve. Third, proposed § 615.5134(f) states that each bank must be able to liquidate any qualified investment in its supplemental liquidity buffer within the timeframe established by the board's liquidity policies at no less than 80 percent of its book value. Fourth, the proposed rule would require a Farm Credit bank to remove from its supplemental liquidity buffer any investment that has, at any time, a market value that is less than 80 percent of its book value. These two provisions are designed to limit losses that the bank may incur on assets held in its supplemental liquidity buffer. As we explained in the preamble to the proposed rule, the liquidity and marketability characteristics of qualified investments in the supplemental liquidity buffer would be called into question if their market value were to fall 20 percent or more below book value. Finally, proposed § 615.5134(f) would require the amount of supplemental liquidity that each bank holds, at a minimum, to: (1) Meet the requirements of the board's liquidity policy; (2) provide excess liquidity beyond the days covered by the liquidity reserve; and (3) comply with the applicable portions of the bank's CFP.
The FCA received comments about the supplemental liquidity buffer from the Council and three Farm Credit banks. None of these commenters opposed the new regulatory requirement that all FCS banks establish a supplemental liquidity buffer. In fact, one commenter pointed out that all the banks have mutually agreed to hold a minimum of 120 days of liquidity, and in practice actually have much more.
A Farm Credit bank commented that the supplemental liquidity reserve effectively increases the days of liquidity for System banks. As a result, the commenter claimed the supplemental liquidity buffer will compel System banks to further lengthen the maturity of their liabilities and potentially reduce the issuance of Discount Notes to fund their operations. The FCA has already responded to comments that assert our new liquidity regulation diminishes System reliance on discount notes. Before the 2008 crisis, FCS banks voluntarily held levels of liquidity far in excess of what the FCA requires under this final rule without detriment to the Discount Notes program.
The Council and two banks opposed two provisions in proposed § 615.5134(f) that would require the market value of all qualified investments in the bank's supplemental liquidity buffer to remain at or above 80 percent of book value. These commenters deem this benchmark as an inappropriate regulatory requirement because, in their opinion, it is subjective, inflexible, unduly restrictive, and arbitrary. According to these three commenters, interest rate fluctuations could cause the market value of an asset to fall below 80 percent of its book value, but the asset could, nevertheless, remain marketable and liquid. Although a System bank may be less willing to sell securities that have declined in market value, the commenters point out that it could still liquidate these assets in most circumstances if the need to raise cash arises. From the commenters' perspective, the premise that a 20-percent decline in value impairs the marketability and liquidity of a security lacks sound support or substantiation. For these reasons, the commenters ask the FCA to eliminate these two provisions from the final regulation.
Redesignated and final § 615.5134(e) continues to require every qualified investment in the bank's supplemental liquidity buffer to retain a market value that equals or exceeds 80 percent of its book value. The FCA reasons that the liquidity reserve, combined with the supplemental liquidity buffer significantly fortify each FCS bank and the System as a whole so they can withstand a future financial crisis. Requiring all qualified investments in the supplemental liquidity buffer to retain at least 80 percent of their book value ensures that each FCS bank has a sufficient quantity of high quality liquid assets to outlast adverse economic or financial conditions that obstruct the System's access to the debt market. We are concerned that liquidation of assets at a loss would be problematic at any time, but especially during a crisis. Investments that can be liquidated only at substantial discounts may not provide the bank with adequate funds to pay its obligations when market access becomes impeded and, therefore, they would not comprise a stable funding source during times of financial stress. Also, the resulting recognition of loss could further exacerbate the financial stress being experienced by an individual FCS bank and the entire System. Additionally, if these types of investments could not be liquidated, or could be sold only at a significant loss, the alternative of a repo transaction to provide liquidity at that level of discount would most likely not be available given concerns as to their actual value. This 80-percent requirement ensures that all qualified investments in each bank's supplemental liquidity buffer provide a source of high quality assets that could
The FCA has revised its final rule so the 80-percent requirement is less burdensome to FCS banks. The proposed rule would have required banks to apply an 85-percent discount to all assets in the supplemental liquidity reserve that did not otherwise qualify for the different levels of the liquidity reserve. Under final § 615.5134(e), each investment in the supplemental liquidity buffer that has a market value of at least 80 percent of its book value, but does not qualify for Levels 1, 2, or 3 of the liquidity reserve, must be discounted to (multiplied by) 90 percent of its book value. This 90-percent discount is less steep than the 85-percent rate that the FCA originally proposed. Additionally, this 90-percent rate is more consistent with § 615.5134(b)(3) of our existing regulation which establishes a 90-percent discount for securities with greater risks.
The existing regulation requires all Farm Credit banks to have a contingency funding plan that addresses liquidity shortfalls during market disruptions. A CFP is a blueprint that helps financial institutions to respond to contingent liquidity events that may arise from external factors that adversely affect the financial system, or they may be specific to the conditions at an individual institution. The 2008 crisis revealed actual and potential vulnerabilities in contingency planning at FCS banks. As a result, the FCA proposed regulatory amendments that are designed to strengthen the System's contingency funding plans.
Proposed § 615.5134(h) would require each Farm Credit bank to have a CFP that ensures sources of liquidity are sufficient to fund normal operations under a variety of stress events. Whereas the existing regulation only requires the CFP to address liquidity shortfalls caused by market disruptions, the proposed rule would require the CFP to explicitly cover other stress events that threaten the bank's liquidity, such as: (1) Rapid increases in loan demand; (2) unexpected draws on unfunded commitments; (3) difficulties in renewing or replacing funding with desired terms or structures; (4) pledging collateral with counterparties; and (5) reduced market access.
Additionally, the proposed rule would require each FCS bank to maintain an adequate level of unencumbered and marketable assets in its liquidity reserve that could be converted into cash to meet its net liquidity needs based on estimated cash inflows and outflows for a 30-day time horizon under an acute stress scenario. The objective of this requirement is to instill discipline at each Farm Credit bank. As an integral and critical part of its contingency planning, the FCA expects each bank to be able to evaluate its expected funding needs and its available funding sources during reasonably foreseeable stress scenarios. In this context, the FCA expects each System bank to analyze its cash inflows and outflows, and its access to funding at different phases of a plausible, but acute, liquidity stress event that continues for 30 days.
Proposed § 615.5134(h) would require the CFP to address four specific areas that are essential to the bank's efforts to mitigate its liquidity risk. Taken together, these four areas constitute an emergency preparedness plan that should enable the bank to effectively cope with a full range of contingency that could endanger its liquidity. More specifically, the proposed rule would require the CFP to:
• Be customized to the financial condition and liquidity risk of the bank and the board's liquidity policy. As such, the CFP should be commensurate with the complexity, risk profile and scope of the bank's operations;
• Identify funding alternatives that the Farm Credit bank can implement whenever its access to funding is impeded. At a minimum, these funding alternatives must include arrangements for pledging collateral to secure funding and possible initiatives to raise additional capital;
• Mandate periodic stress testing, which would analyze the possible impacts on the bank's cash inflows and outflows, liquidity position, profitability and solvency under a variety of stress scenarios; and
• Establish a process for managing events that imperil the bank's liquidity, and assign appropriate personnel and implement executable action plans that carry out the CFP.
The Council and one Farm Credit bank commented on the proposed rule's provisions governing the CFP. The Council acknowledged that proposed § 615.5134(h) is consistent with the approach of the Federal banking agencies, but it judged the provision as “too detailed.” In the commenter's opinion, the provisions of proposed § 615.5134(h) are more appropriate for a policy statement, rather than a regulation. Accordingly, the commenter urged us to revert to the generalized approach of the existing regulation, which in the commenter's view, would grant Farm Credit banks greater flexibility to develop and implement the CFP as circumstances change over time.
The FCA denies this request. As explained earlier, the purpose of this regulatory provision is to correct deficiencies in contingency funding planning at FCS banks that the 2008 crisis revealed.
Contingency funding planning is an essential and crucial element of effective liquidity risk management that enables Farm Credit banks to meet their obligations and continue operations as economic or financial adversity strikes. The FCA's new approach requires the CFP to address specific core issues which are essential to the bank's ability to continue funding its normal operations under a variety of plausible stress scenarios. Additionally, our approach grants FCS banks the flexibility that the commenter seeks by stipulating that each bank must tailor its CFP to its unique liquidity risk profile and tolerance level. In this context, our regulatory approach strikes an appropriate balance by instilling greater discipline in the contingency funding planning process at Farm Credit banks while preserving the banks' flexibility to devise and revise a CFP that addresses its own unique circumstances and conditions.
Both commenters objected to the provision in the proposed rule that would require System banks to conduct periodic stress tests on their cash inflows and outflows, liquidity position, profitability and solvency under a variety of stress scenarios. According to these commenters, additional stress case scenarios are redundant with the investment management regulations, which already require quarterly stress tests. From the commenters' perspective, this new regulatory requirement does not improve effective liquidity management at FCS banks.
The FCA responds that redesignated and final § 615.5134(f)(3) specifically requires stress testing of those factors (such as the bank's cash inflow and outflows, liquidity position, profitability, and solvency) which are key indicators of liquidity. In contrast, the applicable provision of the investment management regulation, § 615.5133(f)(4), focuses on the stress testing in an asset-liability management context. Although some overlap exists, § 615.5133(f) and final and redesignated § 615.5134(f)(3) are neither duplicative, nor in conflict with each other. Instead, the two provisions complement each other as § 615.5133(f) addresses stress testing from a global prospective while final § 615.5134(f) requires specialized stress tests that probe the bank's ability to withstand shocks to its liquidity.
The Council asked the FCA to lessen the stress testing requirement for liquidity, which it views as unduly burdensome. The commenter claims that it would be more effective if managers spent more time on monitoring markets rather than performing “numerous stress tests of implausible and improbable events.” From the commenter's perspective, this stress testing requirement does not effectively improve safety and soundness, and the burdens of this provision outweigh its benefits.
The FCA disagrees that stress testing for liquidity will only marginally improve safety and soundness at System banks, or that this regulatory provision is unduly burdensome. The commenter has provided no evidence that stress testing distracts from the bank's ability to monitor markets. Stress tests should be appropriate for the bank's business model and the complexity of its operations. Similarly, stress tests should be based on plausible and probable assumptions concerning stress events that could adversely affect the bank's ability to pay its obligations and continue normal operations during times of economic or financial turbulence. Stress testing is an integral part of effective liquidity risk management that will detect vulnerabilities in the bank's liquidity management early on so management can take corrective action. Appropriate stress testing is an effective liquidity risk management tool that effectively strengthens safety and soundness at FCS banks. From a regulatory perspective, the burdens of the stress testing requirement in final § 615.5134(f)(3) is minimal, while the benefits are great.
The FCA made three non-substantive technical corrections to this regulatory provision. The first sentence of proposed § 615.5134(h) has been broken into two sentences in final and redesignated § 615.5134(f). Additionally, the proposed rule defined stress events as “including” specific occurrences, whereas the final rule states that stress events “include, but are not limited to” these same occurrences. These changes clarify the scope of this provision without substantively altering its meaning. In the second to last sentence of the main paragraph of this provision, we changed “based on estimated cash inflows and outflows for a 30-day time horizon under an acute stress scenario” to “based on estimated cash inflows and outflows under an acute stress scenario for 30 days.” This revision corrects the grammar of this provision and enhances its clarity, without changing its meaning. Finally, we made two technical revisions in final and redesignated § 615.5134(f)(3). We changed “Requiring periodic stress testing, which analyzes the possible impacts” to “Requiring periodic stress testing that analyzes the possible effects.” Changing “which” to “that” corrects a grammatical error. We corrected the syntax of this provision by changing “impacts” to “effects.” In the context of this sentence, “effects” is more accurate than “impacts.” Neither of these revisions is substantive.
The FCA proposed to strengthen its supervisory and regulatory oversight of liquidity management at Farm Credit banks by adding a new reservation of authority provision to this regulation. Under proposed § 615.5134(i), the FCA would expressly reserve the right to require Farm Credit banks, either individually or jointly, to adjust their treatment of any asset in their liquidity reserves so they always maintain liquidity that is sufficient and commensurate for the risks they face.
The FCA justified this reservation of authority by invoking its Congressional mandate to ensure that FCS institutions comply with applicable laws, fulfill their public policy mission to finance agriculture and other specified activities in rural America, and operate safely and soundly. The Act grants the FCA comprehensive powers to examine, supervise, and regulate the FCS. The FCA reasoned that it must be able to act decisively when a sudden external crisis threatened the System's liquidity.
The Council and a Farm Credit bank opposed proposed § 615.5134(i), and asked the FCA to withdraw it.
After considering comments received, the FCA has decided to omit the reservation of authority from the final regulation. The FCA has comprehensive supervisory authority over all FCS institutions. As a result, the FCA through its examination and enforcement authorities can compel Farm Credit banks, individually or jointly, to promptly take specified action to correct deficiencies in their liquidity management practices if internal or external circumstances so warranted. By approving all obligations that FCS banks issue to fund System operations, and prescribing collateral requirements for such debt, the FCA has an additional mechanism for regulating System liquidity.
As the commenters point out, the FCA may determine in other situations that the best course of action is to relax the liquidity requirements on FCS institutions. In fact, an existing regulation, § 615.5136, authorizes the FCA during an emergency to: (1) Increase the amount of eligible investments that FCS banks may hold pursuant to § 615.5132; or (2) waive or modify the liquidity reserve requirement. As noted in the preamble to the proposed rule, the FCA Board passed a Market Emergency Standby Resolution on November 13, 2008 that would waive the 90-day liquidity reserve requirement for a limited period of time if a crisis shuts or severely restricts the System's access to the debt markets.
For these reasons, the FCA determines it can effectively exercise its supervisory authority over FCS banks during times of economic, financial, or market adversity without inserting the reservation of authority into the liquidity regulation. Because we have omitted the reservation of authority from the final rule, we do not need to address whether it would have violated the APA.
Pursuant to section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 601
Accounting, Agriculture, Banks, banking, Government securities, Investments, Rural areas.
For the reasons stated in the preamble, part 615 of chapter VI, title 12 of the Code of Federal Regulations is amended as follows:
Secs. 1.5, 1.7, 1.10, 1.11, 1.12, 2.2, 2.3, 2.4, 2.5, 2.12, 3.1, 3.7, 3.11, 3.25, 4.3, 4.3A, 4.9, 4.14B, 4.25, 5.9, 5.17, 6.20, 6.26, 8.0, 8.3, 8.4, 8.6, 8.8, 8.10, 8.12 of the Farm Credit Act (12 U.S.C. 2013, 2015, 2018, 2019, 2020, 2073, 2074, 2075, 2076, 2093, 2122, 2128, 2132, 2146, 2154, 2154a, 2160, 2202b, 2211, 2243, 2252, 2278b, 2278b-6, 2279aa,
(a)
(2)
(i) The purpose and objectives of the liquidity reserve;
(ii) Diversification requirements for the liquidity reserve portfolio;
(iii) The target amount of days of liquidity that the bank needs based on its business model and risk profile;
(iv) Delegations of authority pertaining to the liquidity reserve; and
(v) Reporting requirements, which at a minimum must require management to report to the board at least once every quarter about compliance with the bank's liquidity policy and the performance of the liquidity reserve portfolio. However, management must report any deviation from the bank's liquidity policy, or failure to meet the board's liquidity targets to the board before the end of the quarter if such deviation or failure has the potential to cause material loss to the bank.
(b)
(1) Days 1 through 15 only with Level 1 instruments;
(2) Days 16 through 30 only with Level 1 and Level 2 instruments; and
(3) Days 31 through 90 with Level 1, Level 2, and Level 3 instruments.
(c)
(d)
(1) Can be easily and quickly converted into cash with little or no loss in value;
(2) Exhibits low credit and market risks;
(3) Has ease and certainty of valuation; and
(4) Except for money market instruments, can be easily bought and sold in active and sizeable markets without significantly affecting prices.
(e)
(f)
(1) Be customized to the financial condition and liquidity risk profile of the bank and the board's liquidity risk tolerance policy.
(2) Identify funding alternatives that the Farm Credit bank can implement whenever access to funding is impeded, which must include, at a minimum, arrangements for pledging collateral to secure funding and possible initiatives to raise additional capital.
(3) Require periodic stress testing that analyzes the possible effects on the bank's cash inflows and outflows, liquidity position, profitability and solvency under a variety of stress scenarios.
(4) Establish a process for managing events that imperil the bank's liquidity, and assign appropriate personnel and implement executable action plans that carry out the CFP.