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Farm Credit Administration.
Final rule.
The Farm Credit Administration (FCA) adopts as final without change an interim final rule which amended FCA regulations to remove the requirement that Farm Credit System (System) banks and associations hold non-binding, advisory votes on senior officer compensation in certain circumstances.
On March 31, 2014, the FCA published the interim final rule (79 FR 17854) removing the FCA regulatory requirement that (1) associations hold non-binding advisory votes on senior officer compensation when 5 percent of the voting stockholders petition for the vote, and (2) Farm Credit banks and associations hold non-binding advisory votes on senior officer compensation if senior officer compensation increased by 15 percent or more from the previous reporting period (hereafter referred to as “advisory voting rule”).
The FCA received two comments on the interim final rule. In its comment letter, the Farm Credit Council (Council), on behalf of its System members, supported the FCA deleting the non-binding, advisory vote provisions in response to the actions taken by Congress in both the Appropriations Act and the Farm Bill. In its comment letter, the Independent Community Bankers of America (ICBA) expressed the view that the FCA did not need to remove the advisory vote provisions in order to comply with recent Congressional action and suggested that FCA modify the rule through a re-proposal. The ICBA asserted that neither the Appropriations Act nor the Farm Bill require the FCA to withdraw the advisory vote provisions and that a re-proposal would pose no compliance conflict. The ICBA comment letter also mentioned several times the need to allow non-binding, advisory votes at System institutions.
After careful consideration of the comments, the FCA has determined that no changes to the interim final rule are warranted. FCA believes that further notice and comment rulemaking on this subject would be neither practical nor meaningful based on the aforementioned Congressional actions. We note, however, in response to the commenter that advisory votes are not prohibited by this rule. System institutions may employ advisory votes of shareholders on a variety of topics.
Therefore, the FCA adopts as a final rule the interim final rule, which removed from parts 611, 620, and 630 the requirement for advisory voting. Specifically, the following non-binding advisory voting provisions are withdrawn:
§ 611.100(a), defining the term “advisory vote”;
§ 611.360, requiring policies and procedures for non-binding, advisory votes on senior officer compensation;
§ 611.410, addressing non-binding, advisory votes on senior officer compensation;
§ 620.5(a)(11), requiring disclosure of any advisory votes held during the reporting year at the institution;
§ 620.6(c)(6), requiring disclosure (adjacent to the compensation table) in the annual report of a stockholder's right to petition for a non-binding, advisory vote on senior officer compensation; and
§ 630.20(i) (last sentence), requiring disclosure of any advisory votes held during the reporting year within the System.
Pursuant to section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 601
Agriculture, Banks, banking, Rural areas.
Accounting, Agriculture, Banks, banking, Reporting and recordkeeping requirements, Rural areas.
Accounting, Agriculture, Banks, banking, Organization and functions (Government agencies), Reporting and recordkeeping requirements, Rural areas.
Accordingly, the interim rule amending 12 CFR parts 611, 620, and 630, which was published on March 31, 2014 (79 FR 17854), is adopted as a final rule without changes.
Bureau of Consumer Financial Protection.
Final rule.
On September 26, 2013, 78 FR 59163, the Consumer Financial Protection Bureau (Bureau) published in the
This final rule takes effect on July 18, 2014.
John R. Coleman, Senior Counsel, Legal Division, Consumer Financial Protection Bureau, 1700 G Street NW., Washington, DC 20552; at (202) 435-7254.
On June 29, 2012, the Bureau published in the
On September 26, 2013, 78 FR 59163, the Bureau published its interim final rule establishing procedures for the issuance of a temporary cease-and-desist order (TCDO) pursuant to section 1053(c) of the Dodd-Frank Act. In developing the interim final rule, the Bureau considered the procedures related to temporary cease-and-desist orders that are followed by other regulatory agencies, including the FDIC, the Securities and Exchange Commission, and the Office of the Comptroller of the Currency. The interim final rule most closely follows the FDIC's approach as codified in 12 CFR 308.131. The Bureau issued the interim final rule to clarify (1) the basis for the issuance of a TCDO; (2) the content, scope, and form of a TCDO; (3) the procedures governing the issuance of a TCDO and the remedies available to the Bureau in issuing a TCDO; and (4) the rights of persons subject to a TCDO.
The interim final rule described each section of the rule and explained the basis of the rule with reference to rules of other agencies as appropriate. After reviewing and considering the single public comment offered, the Bureau adopts the interim final rule without change.
The Bureau promulgates this final rule pursuant to its authority to implement section 1053 of the Dodd-Frank Act, 12 U.S.C. 5563(e), as well as its general rulemaking authority to promulgate rules necessary or appropriate to carry out the Federal consumer financial laws, 12 U.S.C. 5512(b)(1).
In response to the interim final rule, the Bureau received one comment letter that did not contain any specific comments or suggestions pertaining to the interim final rule. Accordingly, the Bureau is adopting the interim final rule without change.
In developing the interim final and final rules, the Bureau has considered the potential benefits, costs, and impacts and has consulted or offered to consult with the prudential regulators, the Department of Housing and Urban Development, and the Federal Trade Commission, including with regard to consistency with any prudential, market, or systemic objectives administered by such agencies.
The Dodd-Frank Act requires the Bureau to prescribe rules establishing such procedures as may be necessary to carry out section 1053 of the Act, which provides for temporary cease-and-orders in subsection (c). The final rule itself does not impose significant costs upon covered persons, but, consistent with section 1053, provides a straightforward and efficient process for the issuance of a temporary cease-and-desist order, and a direct route to judicial review.
The final rule has no unique impact on insured depository institutions or insured credit unions with $10 billion or less in assets described in section 1026(a) of the Dodd-Frank Act, nor does it have a unique impact on rural consumers.
As the Bureau noted in publishing the interim final rule, this rule relates solely
The Bureau has determined that the regulations in this subpart do not impose any new recordkeeping, reporting, or disclosure requirements on covered entities or members of the public that would constitute collections of information requiring approval under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Administrative practice and procedure, Banking, Banks, Consumer protection, Credit, Credit unions, Law enforcement, National banks, Savings associations, Trade practices.
For the reasons set forth above, the interim final rule amending 12 CFR part 1081 published at 78 FR 59163, September 26, 2013, is adopted as a final rule without change.
Food and Drug Administration, HHS.
Final order.
The Food and Drug Administration (FDA) is issuing a final order to reclassify the blade-form endosseous dental implant, a preamendments class III device, into class II (special controls). On its own initiative, based on new information, FDA is revising the classification of blade-form endosseous dental implants.
This order is effective July 18, 2014.
Michael J. Ryan, Center for Devices and Radiological Health, 10903 New Hampshire Ave., Bldg. 66, Rm. 1615, Silver Spring, MD 20993, 301-796-6283,
The Federal Food, Drug, and Cosmetic Act (the FD&C Act), as amended by the Medical Device Amendments of 1976 (the 1976 amendments) (Pub. L. 94-295), the Safe Medical Devices Act of 1990 (Pub. L. 101-629), the Food and Drug Administration Modernization Act of 1997 (FDAMA) (Pub. L. 105-115), the Medical Device User Fee and Modernization Act of 2002 (Pub. L. 107-250), the Medical Devices Technical Corrections Act (Pub. L. 108-214), the Food and Drug Administration Amendments Act of 2007 (Pub. L. 110-85), and the Food and Drug Administration Safety and Innovation Act (FDASIA) (Pub. L. 112-144), among other amendments, established a comprehensive system for the regulation of medical devices intended for human use. Section 513 of the FD&C Act (21 U.S.C. 360c) established three categories (classes) of devices, reflecting the regulatory controls needed to provide reasonable assurance of their safety and effectiveness. The three categories of devices are class I (general controls), class II (special controls), and class III (premarket approval).
Under section 513(d) of the FD&C Act, devices that were in commercial distribution before the enactment of the 1976 amendments, May 28, 1976 (generally referred to as preamendments devices), are classified after FDA has: (1) Received a recommendation from a device classification panel (an FDA advisory committee); (2) published the panel's recommendation for comment, along with a proposed regulation classifying the device; and (3) published a final regulation classifying the device. FDA has classified most preamendments devices under these procedures.
Devices that were not in commercial distribution prior to May 28, 1976 (generally referred to as postamendments devices), are automatically classified by section 513(f) of the FD&C Act into class III without any FDA rulemaking process. Those devices remain in class III and require premarket approval unless, and until, the device is reclassified into class I or II or FDA issues an order finding the device to be substantially equivalent, in accordance with section 513(i) of the FD&C Act, to a predicate device that does not require premarket approval. The Agency determines whether new devices are substantially equivalent to predicate devices by means of premarket notification procedures in section 510(k) of the FD&C Act (21 U.S.C. 360(k)) and 21 CFR part 807.
A preamendments device that has been classified into class III may be marketed by means of premarket notification procedures (510(k) process) without submission of a premarket approval application (PMA) until FDA issues a final order under section 515(b) of the FD&C Act (21 U.S.C. 360e(b)) requiring premarket approval or until the device is subsequently reclassified into class I or class II.
On July 9, 2012, FDASIA was enacted. Section 608(a) of FDASIA amended section 513(e) of the FD&C Act, changing the mechanism for reclassifying a device from rulemaking to an administrative order.
Section 513(e) of the FD&C Act governs reclassification of classified preamendments devices. This section provides that FDA may, by administrative order, reclassify a device based upon “new information.” FDA can initiate a reclassification under section 513(e) of the FD&C Act or an interested person may petition FDA to reclassify a preamendments device. The term “new information,” as used in section 513(e) of the FD&C Act, includes information developed as a result of a reevaluation of the data before the Agency when the device was originally classified, as well as information not presented, not available, or not developed at that time. (See, e.g.,
Reevaluation of the data previously before the Agency is an appropriate basis for subsequent action where the reevaluation is made in light of newly available authority (see
FDA relies upon “valid scientific evidence” in the classification process to determine the level of regulation for devices. To be considered in the reclassification process, the “valid scientific evidence” upon which the Agency relies must be publicly available. Publicly available information excludes trade secret and/or confidential commercial information, e.g., the contents of a pending PMA. See section 520(c) of the FD&C Act (21 U.S.C. 360j(c)). Section 520(h)(4) of the FD&C Act, added by FDAMA, provides that FDA may use, for reclassification of a device, certain information in a PMA 6 years after the application has been approved. This includes information from clinical and preclinical tests or studies that demonstrate the safety or effectiveness of the device but does not include descriptions of methods of manufacture or product composition and other trade secrets.
Section 513(e)(1) of the FD&C Act sets forth the process for issuing a final order. Specifically, prior to the issuance of a final order reclassifying a device, the following must occur: (1) Publication of a proposed order in the
FDA published a proposed order to reclassify this device in the
After consideration of available information on blade-form endosseous dental implants, the proposed order indicated that FDA believed these devices could also be down classified to class II, subject to the identified special controls. As required by section 513(e)(1) of the FD&C Act, on July 18, 2013, FDA also convened a meeting of the Dental Products Panel (the Panel) to consider the existing valid scientific evidence to support reclassification of blade-form endosseous dental implants into class II.
The Panel discussed and agreed that the risks to health for this device were adequately captured as presented by FDA. The Panel deliberations included discussion of whether the risk of bone loss is higher for blade-form dental implants as compared to root-form dental implant devices. The Panel also discussed the technique-sensitive nature of this device and expressed a concern that additional training, which may not be found in the current curriculum for dental schools, is needed prior to the use of this device to address the identified risks to health.
The Panel agreed that the proposed special controls were reasonable to mitigate the identified risks to health but recommended the device labeling include specific patient selection criteria and recommendations for training and education requirements for clinicians using this device. The Panel recommended that companies marketing this device ensure that device-specific training is available to clinicians. The Panel also recommended clinical data as a special control for the purpose of capturing failure rates and adverse event detection.
The special controls as previously proposed by FDA included documented clinical experience for effective use and observed adverse events which addresses the recommendations for patient selection criteria, and failure rate and adverse event detection. Additionally, the special controls include patient labeling which must contain instructions for reporting complications. The patient labeling will also address the concern for failure rate and adverse event detection. To address the Panel's concern related to recommendations for training and education requirements, FDA has added a special control for the device labeling to include qualifications and training requirements for clinicians using this device.
The Panel concluded that general controls alone are not sufficient due to the identified risks to health; however, special controls, in combination with the general controls, can be sufficient to assure the safety and effectiveness of blade-form endosseous dental implants. The Panel agreed that this device should be reclassified into class II (special controls).
In response to the proposed order, FDA received two comments from practicing clinicians. Both of the comments supported reclassification of the devices into class II, and described positive clinical experience regarding the safety and effectiveness of the device. FDA agrees with the comments.
Under section 513(e) of the FD&C Act, FDA is adopting its findings as published in the preamble to the proposed order. FDA is issuing this final order to reclassify the blade-form endosseous dental implant from class III to class II and to establish special controls. Following the effective date of this final order, firms marketing blade-form endosseous dental implants will need either to: (1) Comply with the particular mitigation measures set forth in the special controls or (2) use alternative mitigation measures, but demonstrate to the Agency's satisfaction that those alternative measures identified by the firm will provide at least an equivalent assurance of safety and effectiveness.
Section 510(m) of the FD&C Act provides that FDA may exempt a class II device from the premarket notification requirements under section 510(k) of the FD&C Act if FDA determines that premarket notification is not necessary to provide reasonable assurance of the safety and effectiveness of the devices. FDA has determined that premarket notification is necessary to provide reasonable assurance of safety and effectiveness of blade-form endosseous implants; and therefore, this device type is not exempt from premarket notification requirements.
The Agency has determined under 21 CFR 25.34(b) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required.
This final order establishes special controls that refer to previously approved collections of information found in other FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collections of information in 21 CFR part 812 have been approved under OMB control number 0910-0078; the collections of information in 21 CFR part 807, subpart E, have been approved under OMB control number 0910-0120; the collections of information in 21 CFR part 814, subpart B, have been approved under OMB control number 0910-0231;
Prior to the amendments by FDASIA, section 513(e) of the FD&C Act provided for FDA to issue regulations to reclassify devices. Although section 513(e) of the FD&C Act as amended requires FDA to issue final orders rather than regulations, FDASIA also provides for FDA to revoke previously issued regulations by order. FDA will continue to codify classifications and reclassifications in the Code of Federal Regulations (CFR). Changes resulting from final orders will appear in the CFR as changes to codified classification determinations or as newly codified orders. Therefore, under section 513(e)(1)(A)(i) of the FD&C Act, as amended by FDASIA, in this final order, we are revoking the requirements in 21 CFR 872.3640 related to the classification of blade-form endosseous implants as class III devices and codifying the reclassification of blade-form endosseous into class II.
Medical devices.
Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs, 21 CFR part 872 is amended as follows:
21 U.S.C. 351, 360, 360c, 360e, 360j, 371.
(a)
(b) * * *
(2)
(i) The design characteristics of the device must ensure that the geometry and material composition are consistent with the intended use;
(ii) Mechanical performance (fatigue) testing under simulated physiological conditions to demonstrate maximum load (endurance limit) when the device is subjected to compressive and shear loads;
(iii) Corrosion testing under simulated physiological conditions to demonstrate corrosion potential of each metal or alloy, couple potential for an assembled dissimilar metal implant system, and corrosion rate for an assembled dissimilar metal implant system;
(iv) The device must be demonstrated to be biocompatible;
(v) Sterility testing must demonstrate the sterility of the device;
(vi) Performance testing to evaluate the compatibility of the device in a magnetic resonance (MR) environment;
(vii) Labeling must include a clear description of the technological features, how the device should be used in patients, detailed surgical protocol and restoration procedures, relevant precautions and warnings based on the clinical use of the device, and qualifications and training requirements for device users including technicians and clinicians;
(viii) Patient labeling must contain a description of how the device works, how the device is placed, how the patient needs to care for the implant, possible adverse events and how to report any complications; and
(ix) Documented clinical experience must demonstrate safe and effective use and capture any adverse events observed during clinical use.
Internal Revenue Service (IRS), Treasury.
Temporary regulations.
This document contains temporary regulations modifying regulations promulgated under section 7602(a) of the Internal Revenue Code relating to administrative summonses. Specifically, these temporary regulations clarify that persons with whom the IRS or the Office of Chief Counsel (Chief Counsel) contracts for services described in section 6103(n) and its implementing regulations may be included as persons designated to receive summoned books, papers, records, or other data and to take summoned testimony under oath. These temporary regulations may affect taxpayers, a taxpayer's officers or employees, and any third party who is served with a summons, as well as any other person entitled to notice of a summons. The text of these temporary regulations serves as the text of the proposed regulations (REG-121542-14) set forth in the notice of proposed rulemaking on this subject in the Proposed Rules section in this issue of the
A M Gulas at (202) 317-6834 (not a toll-free number).
These temporary regulations amend Procedure and Administration Regulations (26 CFR part 301) promulgated under section 7602 of the Internal Revenue Code. These temporary regulations make clear that persons described in section 6103(n) and Treas. Reg. § 301.6103(n)-1(a) with whom the IRS or Chief Counsel contracts for services may receive books, papers, records, or other data summoned by the IRS and take testimony of a person who the IRS has summoned as a witness to provide testimony under oath. While IRS officers and employees remain responsible for issuing summonses and developing and conducting examinations, the temporary regulations clarify that contractors are permitted to participate fully in a summons interview. Full participation includes, but is not limited to, receipt, review, and use of summoned books, papers, records, or other data, being present during summons interviews, questioning the person providing testimony under oath, and asking a summoned person's representative to clarify an objection or an assertion of privilege.
The assistance of persons from outside the IRS or Chief Counsel promotes efficient administration and enforcement of laws administered by the IRS, by providing specialized knowledge, skills, or abilities that the IRS officers or employees assigned to the case may not possess. For example, outside persons often assist the IRS in matters involving transfer pricing. To clarify the role of these outside persons, these temporary regulations expressly provide that when an IRS officer or employee summons a taxpayer or other witness to produce books, papers, records, or other data and/or to give testimony, an outside person hired by the IRS or Chief Counsel authorized to receive returns or return information pursuant to section 6103(n) may receive the summoned books, papers, records, or other data and take the testimony of the witness under oath.
When the IRS hires an outside person to assist an IRS officer or employee to review books and papers, analyze data, or take testimony from a summoned witness, the IRS will ensure that the inherently governmental functions associated with section 7602, for example, deciding whether to issue a summons, deciding whom to summon, what information must be produced or who will be required to testify, and issuing the summons, will still be performed by an IRS officer or employee. The contractors' role will be limited to functions that are not inherently governmental, such as taking testimony by asking questions, reviewing books or papers, or analyzing other data. As a further safeguard, the temporary regulations expressly provide that any contractor that the IRS authorizes to ask questions of a summoned witness testifying under oath must do so in the presence and under the guidance of an IRS officer or employee.
The conclusion that contractors may receive summoned books and papers, analyze data, and question summoned witnesses is consistent with Treas. Reg. § 301.7602-2(c)(1)(i)(B) and (c)(1)(ii)
The temporary regulations are effective for summons interviews conducted on or after June 18, 2014. The applicability of the temporary regulations will expire on June 16, 2017.
It has been determined that this Treasury Decision 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. The IRS has determined that sections 553(b) and (d) of the Administrative Procedure Act (5 U.S.C. chapter 5) do not apply to these regulations and because the regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Pursuant to section 7805(f) of the Internal Revenue Code, the IRS will submit these temporary regulations to the Chief Counsel for Advocacy of the Small Business Administration for comments about the regulations' impact on small business.
The principal author of these regulations is A M Gulas of the Office of Associate Chief Counsel (Procedure and Administration).
Employment taxes, Estate taxes, Excise taxes, Gift taxes, Income taxes, Penalties, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 301 is amended as follows:
The authority citation for part 301 continues to read in part as follows:
26 U.S.C. 7805 * * *
(a) [Reserved]. For further guidance, see § 301.7602-1(a).
(b) through (b)(2) [Reserved]. For further guidance, see § 301.7602-1(b) through (b)(2).
(b)(3)
(c) [Reserved]. For further guidance, see § 301.7602-1(c).
(d)
(e)
Coast Guard, DHS.
Notice of enforcement of regulation.
The Coast Guard will enforce the safety zone in 33 CFR 165.943 for the Point to LaPointe Swim in LaPointe, WI from 7:20 a.m. through 10 a.m. on August 2, 2014. This action is necessary to protect participants and spectators during the Point to LaPointe swim. During the enforcement period, entry into, transiting, or anchoring within the safety zone is prohibited unless authorized by the Captain of the Port Duluth or his designated on-scene representative.
The regulations in 33 CFR 165.943(b) will be enforced from 7:20 a.m. through 10 a.m. on August 2, 2014, for the Point to LaPointe Swim safety zone, § 165.943(a)(7).
If you have questions on this document, call or email LT Judson Coleman, Chief of Waterways Management, Coast Guard; telephone (218) 725-3818, email
The Coast Guard will enforce the safety zone for the annual Point to LaPointe Swim in 33 CFR 165.943(a)(7) from 7:20 a.m. through 10 a.m. on August 2, 2014 on all waters between Bayfield, WI and Madeline Island, WI within an imaginary line created by the following coordinates: 46°48′50.97″ N, 090°48′44.28″ W, moving southeast to 46°46′44.90″ N, 090°47′33.21″ W, then moving northeast to 46°46′52.51″ N, 090°47′17.14″ W, then moving northwest to 46°49′03.23″ N, 090°48′25.12″ W and finally running back to the starting point.
Entry into, transiting, or anchoring within the safety zone is prohibited unless authorized by the Captain of the Port Duluth or his designated on-scene representative. The Captain of the Port's designated on-scene representative may be contacted via VHF Channel 16.
This document is issued under authority of 33 CFR 165.943 and 5 U.S.C. 552(a). In addition to this publication in the
Coast Guard, DHS.
Final rule.
The Coast Guard is amending the safety zones for the “RI Air National Guard Air Show” and the “Swim Buzzards Bay” events. This amendment adds an additional month to the eligible dates for which the Safety Zones apply to each of these two events.
This rule is effective July 18, 2014.
Documents mentioned in this preamble are part of docket USCG-2014-0061. To view documents mentioned in the preamble as being available in the docket, go to
If you have questions on this rule, call Mr. Edward G. LeBlanc at Coast Guard Sector Southeastern New England, 401-435-2351. If you have questions on viewing the docket, please call Renee V. Wright, Program Manager, Docket Operations, telephone 202-366-9826.
On April 8, 2014, we published a notice of rulemaking (NPRM) entitled “Safety Zones; Annually Recurring Events in Coast Guard Southeastern New England Captain of the Port Zone” in the
The legal basis for this rule is 33 U.S.C. 1231, 46 U.S.C. Chapter 701, 3306, 3703; 50 U.S.C. 191, 195; Public Law 107-295, 116 Stat. 2064; and Department of Homeland Security Delegation No. 0170.1, which collectively authorize the Coast Guard to define safety zones.
On May 22, 2012, the Coast Guard published a Final Rule in the
For the Air Show, the month of May is added to June and July, so that the safety zone at 33 CFR 165.173 now applies to one weekend in May, June, or July, rather than just June or July as was applicable under the original regulation being amended.
For the Swim, the month of June is added to July and August, so that the safety zone at 33 CFR 165.173 applies to one Saturday or Sunday in June, July, or August, rather than just July or August as was applicable under the original regulation being amended.
These revisions provide a larger window of eligible dates for the sponsors of each event to better coordinate with other waterway users, major participants, and state and local safety officials.
No comments were received, and no changes were made to the language contained in the NPRM.
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 Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order.
We expect the economic impact of this rule to be so minimal that a full Regulatory Evaluation is unnecessary. Although this regulation may have some impact on the public, the potential impact will be minimized for the following reasons: The Air Show will be limited to only a single three-day weekend period (Friday, Saturday, and Sunday) potentially in the month of May, and the Air Show has occurred annually for many years with no negative public comments or concerns regarding impacts to navigation. The Swim will be limited to only a single
Notifications are made to the local maritime community through the Local Notice to Mariners well in advance of the Air Show and Swim. No new or additional restrictions are imposed on vessel traffic.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this rule will have a significant economic impact on a substantial number of small entities. 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 received no comments from the Small Business Administration on this rule.
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 affects the following entities, some of which might be small entities: owners or operators of vessels intending to transit, fish, or anchor in the area of the Air Show as listed in section 6.2 of the Table to 33 CFR 165.173.
The rule will not have a significant economic impact on a substantial number of small entities for the following reasons: The Air Show is limited to only a single three-day weekend period (Friday, Saturday, and Sunday) during the entire eligible period (May, June, July), and the Air Show has occurred annually for many years with no negative public concerns regarding impacts to navigation. The Swim is limited to a single Saturday or Sunday during the entire eligible period (June, July, August), and the Swim has occurred annually for many years with few negative public concerns regarding impacts to navigation, and those concerns have been readily and satisfactorily resolved.
Notifications are made to the local maritime community through the Local Notice to Mariners well in advance of the Air Show and Swim. No new or additional restrictions are imposed on vessel traffic.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), in the NPRM we offered to assist small entities in understanding this rule so that they can better evaluate its effects on them and participate in the rulemaking process.
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 calls for no 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 does not result in such expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This rule will not cause 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 will not create an environmental risk to health or risk to safety that might 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 rule 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 concluded this action appears to be one of a category of actions which do not individually or cumulatively have a significant effect on the human environment.
Any comments made in response to the previously published Notice of Proposed Rulemaking for this action
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. 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.
Environmental Protection Agency (EPA).
Final rule.
This regulation amends tolerances for residues of pyroxasulfone in or on corn, field, forage and corn, field, grain. K-I Chemical U.S.A. Inc. c/o Landis International, Inc. requested these amended tolerances under the Federal Food, Drug, and Cosmetic Act (FFDCA).
This regulation is effective June 18, 2014. Objections and requests for hearings must be received on or before August 18, 2014, and must be filed in accordance with the instructions provided in 40 CFR part 178 (see also Unit I.C. of the
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPP-2013-0673, is available at
Lois Rossi, Registration Division (7505P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; main telephone number: (703) 305-7090; email address:
You may be potentially affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. The following list of North American Industrial 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:
• Crop production (NAICS code 111).
• Animal production (NAICS code 112).
• Food manufacturing (NAICS code 311).
• Pesticide manufacturing (NAICS code 32532).
You may access a frequently updated electronic version of EPA's tolerance regulations at 40 CFR part 180 through the Government Printing Office's e-CFR site at
Under FFDCA section 408(g), 21 U.S.C. 346a, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. You must file your objection or request a hearing on this regulation in accordance with the instructions provided in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket ID number EPA-HQ-OPP-2013-0673 in the subject line on the first page of your submission. All objections and requests for a hearing must be in writing, and must be received by the Hearing Clerk on or before August 18, 2014. Addresses for mail and hand delivery of objections and hearing requests are provided in 40 CFR 178.25(b).
In addition to filing an objection or hearing request with the Hearing Clerk as described in 40 CFR part 178, please submit a copy of the filing (excluding any Confidential Business Information (CBI)) for inclusion in the public docket. Information not marked confidential pursuant to 40 CFR part 2 may be disclosed publicly by EPA without prior notice. Submit the non-CBI copy of your objection or hearing request, identified by docket ID number EPA-HQ-OPP-2013-0673, by one of the following methods:
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Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
In the
Section 408(b)(2)(A)(i) of FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) of FFDCA defines “safe” to mean that “there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) of FFDCA requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue. . . .”
Consistent with FFDCA section 408(b)(2)(D), and the factors specified in FFDCA section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of this action. EPA has sufficient data to assess the hazards of and to make a determination on aggregate exposure for pyroxasulfone, including exposure resulting from the tolerances established by this action. EPA's assessment of exposures and risks associated with pyroxasulfone follows.
In the
Once a pesticide's toxicological profile is determined, EPA identifies toxicological points of departure (POD) and levels of concern to use in evaluating the risk posed by human exposure to the pesticide. For hazards that have a threshold below which there is no appreciable risk, the toxicological POD is used as the basis for derivation of reference values for risk assessment. PODs are developed based on a careful analysis of the doses in each toxicological study to determine the dose at which no adverse effects are observed (the NOAEL) and the lowest dose at which adverse effects of concern are identified (the LOAEL). Uncertainty/safety factors are used in conjunction with the POD to calculate a safe exposure level—generally referred to as a population-adjusted dose (PAD) or a reference dose (RfD)—and a safe margin of exposure (MOE). For non-threshold risks, the Agency assumes that any amount of exposure will lead to some degree of risk. Thus, the Agency estimates risk in terms of the probability of an occurrence of the adverse effect expected in a lifetime. For more information on the general principles EPA uses in risk characterization and a complete description of the risk assessment process, see
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Based on the Pesticide Root Zone Model/Exposure Analysis Modeling System (PRZM/EXAMS) and Pesticide Root Zone Model Ground Water (PRZM GW), the estimated drinking water concentrations (EDWCs) of pyroxasulfone for acute exposures are estimated to be 17 parts per billion (ppb) for surface water and 210 ppb for ground water. EDWCs of pyroxasulfone for chronic exposures for non-cancer assessments are estimated to be 3.2 ppb for surface water and 174 ppb for ground water.
Modeled estimates of drinking water concentrations were directly entered into the dietary exposure model. For acute dietary risk assessment, the water concentration value of 210 ppb was used to assess the contribution to drinking water. For chronic dietary risk assessment, the water concentration of value 174 ppb was used to assess the contribution to drinking water.
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i. The increased susceptibility is occurring at high doses.
ii. NOAELs and LOAELs have been identified for all effects of concern, and thus a clear dose response has been well defined.
iii. The PODs selected for risk assessment are protective of the fetal/offspring effects.
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i. The toxicity database for pyroxasulfone is complete.
ii. Pyroxasulfone is a neurotoxic chemical and there is evidence of increased susceptibility of offspring with regard to neurotoxic effects in the rat DNT study. There is also evidence of increased susceptibility of fetuses/offspring with regard to non-neurotoxic effects in the rabbit developmental toxicity study. However, concern for the increased susceptibility is low for the reasons stated in Unit III.D.2.; therefore, EPA determined that a 10X FQPA SF is not necessary to protect infants and children.
iii. There are no residual uncertainties identified in the exposure databases. The dietary food exposure assessments were performed based on 100 PCT and adjusted tolerance-level residues. EPA made conservative (protective) assumptions in the ground and surface
EPA determines whether acute and chronic dietary pesticide exposures are safe by comparing aggregate exposure estimates to the acute PAD (aPAD) and chronic PAD (cPAD). For linear cancer risks, EPA calculates the lifetime probability of acquiring cancer given the estimated aggregate exposure. Short-, intermediate-, and chronic-term risks are evaluated by comparing the estimated aggregate food, water, and residential exposure to the appropriate PODs to ensure that an adequate MOE exists.
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Adequate enforcement methodology (a liquid chromatography/mass spectrometry/mass spectrometry (LC/MS/MS) method) is available to enforce the tolerance expression. The method may be requested from: Chief, Analytical Chemistry Branch, Environmental Science Center, 701 Mapes Rd., Ft. Meade, MD 20755-5350; telephone number: (410) 305-2905; email address:
In making its tolerance decisions, EPA seeks to harmonize U.S. tolerances with international standards whenever possible, consistent with U.S. food safety standards and agricultural practices. EPA considers the international maximum residue limits (MRLs) established by the Codex Alimentarius Commission (Codex), as required by FFDCA section 408(b)(4). The Codex Alimentarius is a joint United Nations Food and Agriculture Organization/World Health Organization food standards program, and it is recognized as an international food safety standards-setting organization in trade agreements to which the United States is a party. EPA may establish a tolerance that is different from a Codex MRL; however, FFDCA section 408(b)(4) requires that EPA explain the reasons for departing from the Codex level. The Codex has not established a MRL for pyroxasulfone.
Therefore, tolerances are established for residues of pyroxasulfone, [3-[[[5-(difluoromethoxy)-1-methyl-3-(trifluoromethyl)-1H-pyrazol-4-yl]methyl]sulfonyl]-4,5-dihydro-5,5-dimethylisoxazole], including its metabolites and degradates, as set forth in the regulatory text.
This final rule establishes tolerances under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled “Regulatory Planning and Review” (58 FR 51735, October 4, 1993). Because this final rule has been exempted from review under Executive Order 12866, this final rule is not subject to Executive Order 13211, entitled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) or Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997). This final rule does not contain any information collections subject to OMB approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Since tolerances and exemptions that are established on the basis of a petition under FFDCA section 408(d), such as the tolerance in this final rule, do not require the issuance of a proposed rule, the requirements of the Regulatory Flexibility Act (RFA) (5 U.S.C. 601
This final rule directly regulates growers, food processors, food handlers, and food retailers, not States or tribes, nor does this action alter the relationships or distribution of power and responsibilities established by Congress in the preemption provisions of FFDCA section 408(n)(4). As such, the Agency has determined that this action will not have a substantial direct effect on States or tribal governments, on the relationship between the national government and the States or tribal governments, or on the distribution of power and responsibilities among the various levels of government or between the Federal Government and Indian tribes. Thus, the Agency has determined that Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999) and Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000) do not apply to this final rule. In addition, this final rule does not impose any enforceable duty or contain any unfunded mandate as described under Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) (2 U.S.C. 1501
This action does not involve any technical standards that would require
Pursuant to the Congressional Review Act (5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
Therefore, 40 CFR chapter I is amended as follows:
21 U.S.C. 321(q), 346a and 371.
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Environmental Protection Agency.
Final rule.
The Environmental Protection Agency (EPA) Region 2 announces the deletion of the Federal Creosote Superfund Site (Site) located in the Borough of Manville, New Jersey, from the National Priorities List (NPL). The NPL, promulgated pursuant to section 105 of the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) of 1980, as amended, is an appendix of the National Oil and Hazardous Substances Pollution Contingency Plan (NCP). The EPA and the State of New Jersey, through the New Jersey Department of Environmental Protection, have determined that all appropriate response actions under CERCLA, other than long-term groundwater monitoring, and five-year reviews, have been completed. However, this deletion does not preclude future actions under Superfund.
This action is effective June 18, 2014.
Submit your comments, identified by Docket ID no. EPA-HQ-SFUND-1999-0013, by one of the following methods:
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Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.
Rich Puvogel, Remedial Project Manager, U.S. Environmental Protection Agency, Region II, 290 Broadway, 19th Floor, New York, New York 10007-1866, (212) 637-4410, or email
The site to be deleted from the NPL is: Federal Creosote Superfund Site, Manville, New Jersey. A Notice of Intent to Delete for this Site was published in the
The closing date for comments on the Notice of Intent to Delete was April 4, 2014. One comment was received. The comment suggested that a process be established to protect against potential future exposures to subsurface contaminants brought to the surface by redevelopment activities. Deed notices apply adequate restrictions on properties to protect against redevelopment activities that have the potential to deposit contaminated subsurface soils on the land surface. Deed notices, a required component of the selected remedy, have been implemented at the Federal Creosote Superfund Site. The selected remedy, which adequately protects human health and the environment, has been fully implemented and therefore satisfies the deletion criteria of the National Contingency Plan.
EPA maintains the NPL as the list of sites that appear to present a significant risk to public health, welfare, or the environment. Deletion from the NPL does not preclude further remedial action. Whenever there is a significant release from a site deleted from the NPL, the deleted site may be restored to the NPL without application of the hazard ranking system. Deletion of a site from the NPL does not affect responsible party liability in the unlikely event that future conditions warrant further actions.
Environmental protection, Air pollution control, Chemicals, Hazardous waste, Hazardous substances, Intergovernmental relations, Penalties, Reporting and recordkeeping requirements, Superfund, Water pollution control, Water supply.
For reasons set out in the preamble, 40 CFR part 300 is amended as follows:
33 U.S.C. 1321(c)(2); 42 U.S.C. 9601-9657; E.O. 12777, 56 FR 54757, 3 CFR, 1991 Comp., p. 351; E.O. 12580, 52 FR 2923; 3 CFR, 1987 Comp., p. 193.
Environmental Protection Agency (EPA).
Direct final rule.
EPA is updating the chemical identities of significant new use rules (SNURs) under the Toxic Substances Control Act (TSCA) for 36 chemical substances which were the subject of premanufacture notices (PMNs). This action updates SNURs that were issued using generic chemical names but will now identify the specific chemical name and chemical abstract number.
This rule is effective on August 18, 2014. For purposes of judicial review, this rule shall be promulgated at 1 p.m. (e.s.t.) on July 2, 2014.
Written adverse or critical comments, or notice of intent to submit adverse or critical comments, on this direct final rule must be received on or before July 18, 2014 (see Unit III. of the
For additional information on related reporting requirement dates, see Units I.A. and III. of the
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPPT-2014-0276, by one of the following methods:
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You may be potentially affected by this action if you manufacture, process, or use the chemical substances contained in this rule. The following list of North American Industrial Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers
• Manufacturers or processors of one or more subject chemical substances (NAICS codes 325 and 324110), e.g., chemical manufacturing and petroleum refineries.
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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.
Using direct final procedures, EPA is updating the chemical identity listings SNURs for 36 chemical substances which were the subject of PMNs. The SNURs were previously issued using generic chemical names. This action identifies the specific chemical name and chemical abstract number in the modified SNUR, as this information is now publicly available. EPA is not changing the significant new use reporting requirements, the basis, or the findings for these SNURs. These SNURs will continue to require persons to notify EPA at least 90 days before commencing the manufacture or processing of a chemical substance for any activity designated by these SNURs as a significant new use. Receipt of such notices allows EPA to assess risks that may be presented by the intended uses and, if appropriate, to regulate the proposed use before it occurs.
Previously, 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.” 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 or process the chemical substance for that use. Persons who must report are described in § 721.5.
EPA is issuing these chemical identity changes as a direct final rule, as described in § 721.160(c)(3) and § 721.170(d)(4). In accordance with § 721.160(c)(3)(ii) and § 721.170(d)(4)(i)(B), the effective date of this rule is August 18, 2014 without further notice, unless EPA receives written adverse or critical comments, or notice of intent to submit adverse or critical comments before July 18, 2014.
If EPA receives written adverse or critical comments, or notice of intent to submit adverse or critical comments, on one or more of these SNURs before July 18, 2014, EPA will withdraw the relevant sections of this direct final rule before its effective date. EPA will then issue a proposed SNUR for the chemical substance(s) on which adverse or critical comments were received, providing a 30-day period for public comment.
This rule updates the chemical identity of SNURs for a number of chemical substances. Any person who submits adverse or critical comments, or notice of intent to submit adverse or critical comments, must identify the chemical substance to which it applies. EPA will not withdraw a SNUR modification for a chemical substance not identified in the comment.
This rule modifies SNURs for several new chemical substances that were the subject of PMNs, or TSCA section 5(e) consent orders. This action does not alter any obligations under these SNURs and therefore is not a significant action under Executive Order 12866, entitled “Regulatory Planning and Review” (58 FR 51735, October 4, 1993).
According to Paperwork Reduction Act (PRA) (44 U.S.C. 3501
This rule would provide more specific information on the chemical substances subject to the SNURs affected by the rule, and therefore does 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 will be impacted by this rule. As such, EPA has determined that this rule does not impose any enforceable duty, contain any unfunded mandate, or otherwise have any effect on small governments subject to the
This action will 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 “Federalism” (64 FR 43255, August 10, 1999).
This rule does not have Tribal implications because it is not expected to have substantial direct effects on Indian Tribes. This rule does not significantly nor uniquely affect the communities of Indian Tribal governments, nor does it involve or impose any requirements that affect Indian Tribes. Accordingly, the requirements of Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), do not apply to this rule.
This action is not subject to Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because this is not an economically significant regulatory action as defined by Executive Order 12866, and this action does not address environmental health or safety risks disproportionately affecting children.
This action is not subject to Executive Order 13211, entitled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001), because this action is not expected to affect energy supply, distribution, or use and because this action is not a significant regulatory action under Executive Order 12866.
In addition, since this action does not involve any technical standards, NTTAA section 12(d) (15 U.S.C. 272 note), does not apply to this action.
This action does not entail special considerations of environmental justice related issues as delineated by Executive Order 12898, entitled “Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations” (59 FR 7629, February 16, 1994).
Pursuant to the Congressional Review Act (5 U.S.C. 801
Environmental protection, Chemicals, Hazardous substances, Reporting and recordkeeping requirements.
Therefore, 40 CFR part 721 is amended as follows:
15 U.S.C. 2604, 2607, and 2625(c).
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Federal Communications Commission.
Final rule; announcement of effective date.
In this document, the Federal Communications Commission (Commission) announces that the Office of Management and Budget (OMB) has approved, for a period of three years, an information collection associated with the Commission's
The rules associated with the Connect America Phase II state-level commitment elections published at 78 FR 32991, June 3, 2013; 47 CFR 54.312(b)(3), published at 78 FR 48622, August 9, 2013; and 47 CFR 54.313(b) published at 78 FR 38227, June 26, 2013, are effective June 18, 2014.
Ryan Yates, Wireline Competition Bureau at (202) 418-7400 or TTY (202) 418-0484.
This document announces that, on March 11, 2014, OMB approved, for a period of three years, the information collection requirements contained in the Commission's
To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to
As required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507), the FCC is notifying the public that it received OMB approval on March 11, 2014, for the new rules associated with the Connect America Phase II state-level commitment elections and the information collection requirements contained in the Commission's rules at 47 CFR 54.312(b)(3), and 54.313(b). Under 5 CFR part 1320, an agency may not conduct or sponsor a collection of information unless it displays a current, valid OMB Control Number.
No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act that does not display a current, valid OMB Control Number. The OMB Control Number is 3060-1188.
The foregoing notice is required by the Paperwork Reduction Act of 1995, Public Law 104-13, October 1, 1995, and 44 U.S.C. 3507.
The total annual reporting burdens and costs for the respondents are as follows:
Nuclear Regulatory Commission.
Draft regulatory basis; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) is requesting comments on a draft regulatory basis to support the potential amendments to revise a number of existing security-related regulations relating to physical protection of special nuclear material (SNM) at NRC-licensed facilities and in transit, as well as the fitness for duty programs for security officers at certain fuel cycle facilities. Potentially affected licensees include fuel cycle facilities, non-power reactors, research and development facilities, industrial facilities, and certain medical isotope production facilities.
Submit comments by August 4, 2014. Comments received after this date will be considered if it is practical to do so, but the NRC is only able to ensure consideration of comments received on or before this date.
You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):
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Alex Sapountzis, Office of Nuclear Security and Incident Response, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-287-3660, email:
Please refer to Docket ID NRC-2014-0118 when contacting the NRC about the availability of information for this action. You may obtain publicly-available information related to this action by any of the following methods:
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Please include Docket ID NRC-2014-0118 in the subject line of your comment submission, in order to ensure that the NRC is able to make your comment submission available to the public in this docket.
The NRC cautions you not to include identifying or contact information in comment submissions that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
The NRC is requesting comment on a draft regulatory basis to support rulemaking to amend portions of Parts 26 and 73 of Title 10 of the
The specific objectives of these rulemaking efforts are to update SNM physical protection requirements to: (1) Improve consistency and clarity; (2) make generically applicable security requirements similar to those imposed by security orders issued after the terrorist attacks of September 11, 2001; (3) consider risk insights from new National Laboratory studies, operational oversight and inspection activities, and international guidance; and (4) use a risk-informed and performance-based structure. The scope of the regulatory basis includes physical protection of SNM at fuel cycle facilities and other facilities that possess and use SNM, and the physical protection of SNM in transit. Potentially affected licensees include fuel cycle facilities, non-power reactors, research and development facilities, industrial facilities, and certain medical isotope production facilities. The regulatory basis, in part, explains why the NRC believes the existing regulations should be updated, revised and enhanced, presents alternatives to rulemaking, and discusses cost and other impacts of the potential changes.
The NRC requests that stakeholders consider answering the following questions when commenting on the draft regulatory basis:
• Is the NRC considering an appropriate approach for each objective described in the draft regulatory basis? Should implementing material attractiveness and its associated physical protection measures be “voluntary” or should it be “mandatory?” Given that the potentially revised regulations would be material-based rather than facility-based, are the potential regulatory changes sufficiently performance-based to allow licensees of different facility types to effectively implement the potential physical protection performance objectives and strategies for the various categories of special nuclear material?
• Section 3 of the draft regulatory basis discusses the regulatory problems the NRC expects to address through rulemaking. Section 4 presents the desired regulatory changes to address those regulatory problems and Section 5 discusses alternatives to rulemaking considered by the NRC staff. Are there other regulatory problems within or related to the scope of the rulemaking efforts (see Section 1) that the NRC should consider? Are there other approaches or alternatives the NRC should consider to resolve those regulatory problems?
• Section 8 of the draft regulatory basis presents the NRC staff's initial assessment of cost and other impacts for a number of key aspects of the potential regulatory changes (i.e., fixed site physical protection, transportation physical protection, safety-safeguards interface and fitness-for-duty impacts). The NRC staff recognizes that this initial assessment is based on limited data. As such, staff is seeking additional data and input relative to expected and/or unintentional impacts from the desired regulatory changes. What would be the potential impacts to stakeholders/licensees from implementing any of the desired regulatory changes described in this draft regulatory basis (e.g., what would be a reasonable cost estimate for implementation of fatigue requirements for security officers at Category I facilities in accordance to 10 CFR Part 26, Subpart I, including startup and annual costs)?
• The NRC staff recognizes that the security officer work hour data provided voluntarily by licensees in the past and summarized in Attachment 2 of the draft regulatory basis is limited. As such, are there additional data or information (e.g., procedures that demonstrate the licensee has fatigue measures in place for security officers at their site, updated security officer work hour data from the most recent 2-month period and so forth) that would inform the NRC staff's assessment or analysis?
The NRC may post additional materials related to this rulemaking activity to the Federal rulemaking Web site at
The Federal rulemaking Web site allows you to receive alerts when changes or additions occur in a docket folder. To subscribe: (1) Navigate to the docket folder (NRC-2014-0118); (2) click the “Sign up for Email Alerts” link; and (3) enter your email address and select how frequently you would like to receive emails (daily, weekly, or monthly).
The Plain Writing Act of 2010 (Pub. L. 111-274) requires Federal agencies to write documents in a clear, concise, well-organized manner. The NRC has written this document to be consistent with the Plain Writing Act as well as the Presidential Memorandum, “Plain Language in Government Writing,” published June 10, 1998 (63 FR 31883). The NRC requests comment on this document with respect to the clarity and effectiveness of the language used.
For the Nuclear Regulatory Commission.
Federal Trade Commission (“FTC” or “Commission”).
Supplemental notice of proposed rulemaking.
As part of its regulatory review of the Energy Labeling Rule, the Federal Trade Commission proposes to expand coverage of the Lighting Facts label, change the current label categories for refrigerators, revise the ceiling fan label design, and require room air conditioner labels on packaging instead of the units themselves.
Written comments must be received on or before August 18, 2014.
Interested parties may file a comment online or on paper, by following the instructions in the Request for Comment part of the
Hampton Newsome, Attorney, (202)
In a March 15, 2012
This document addresses the remaining issues raised by the Commission or commenters during this regulatory review proceeding and proposes related amendments. These issues include expanded light bulb label coverage, an online label database, more durable labels for appliances, room and portable air conditioner box labels, ceiling fan labels, consolidated refrigerator ranges, updates to furnace labels, QR (“Quick Response”) Codes, bilingual issues, television label updates, a range revision schedule, retailer responsibility, marketplace Web sites, set-top box labeling, clothes dryer labels, and plumbing products. After reviewing the comments received in response to this document, the Commission will publish final amendments as appropriate.
The Commission proposes requiring the Lighting Facts label for decorative and other specialty bulbs that have energy use and light output similar to general service bulbs already labeled under the Rule. On July 19, 2010 (75 FR 41696), the Commission created a new Lighting Facts label for general service light bulbs, which discloses information about the bulb's brightness, estimated annual energy cost, life, color appearance, and energy use.
ASAP, which also supported expanded coverage, focused on labeling bulbs commonly used as substitutes for general service lamps.
In contrast, industry comments argued that Commission's proposal was too broad and would require labels that, in some cases, would provide little benefit to consumers. Instead, they urged the Commission to consider expanded coverage on a product-by-product basis and only impose new requirements if labeling for specific bulb types would aid consumer-purchasing decisions. They also urged the Commission to allow a smaller version of the label for small packages common for specialty bulbs. Finally, these comments opposed the proposal to
The National Electrical Manufacturers Association (NEMA) (#00009-80665), a lighting industry association, raised concerns about the proposal's breadth. NEMA argued that expanded coverage would yield little benefit because consumers have minimal concern about lumen output and energy use when purchasing many of the bulb types included in the Commission's proposal.
NEMA added that candelabra based lamps are small, decorative bulbs with limited space for labeling and that few pin-based lamps (GU-type) are sold to residential consumers. It also explained that the proposal would cover products with low sales or minor energy use, such as B, BA, CA, and G shape lamps that draw fewer than 30 watts or produce fewer than 310 lumens; small diameter reflector lamps with few sales (
In addition, GE noted the proposal covered several commercial bulb shapes with few, if any, high-efficiency alternatives, such as S-lamps and T-lamps used for exit signs, showcases, and appliances. Finally, NEMA recommended that the FTC maintain the Rule's current exclusions,
Although NEMA raised concerns with the proposal's structure and coverage, it acknowledged FTC's authority to consider labeling for additional lighting products. Industry comments, from NEMA and GE, urged the Commission to use that authority to focus on whether additional “labeling or other disclosures will help consumers in making purchasing decisions” as contemplated by EPCA.
Both NEMA and GE recommended that the Commission approach any expanded coverage on a bulb-by-bulb basis to provide regulatory clarity and to ensure that substantial evidence exists for such requirements. GE pointed the Commission to a specific set of bulbs as good candidates for labeling. It explained that about 95% of the decorative incandescent lamp shapes are offered in the G (Globe), CA, B, or BA types, which are available in alternative technologies such as CFL or LED and feature medium screw, candelabra or intermediate screw bases. GE also recommended that the Commission focus on labeling for common lamp types rated at 25 or more watts because models below 25 watts do not consume enough energy to affect consumer purchasing behavior.
Industry members also raised concerns about fitting the required disclosures on packages and lamps. These comments recommended a smaller label and abbreviated content for newly-covered bulbs because many specialty lamp types have smaller packages. Specifically, NEMA urged the Commission to allow a smaller version of the label, which discloses only brightness (average initial lumens), life, and energy usage (wattage). NEMA also repeated its earlier proposal to allow the Rule's current compressed label for packages up to 48 square inches in size, instead of the Rule's current 24 square inch threshold.
Finally, NEMA and GE strongly opposed the Commission's proposal to change the definition of “general service lamp” to expand label coverage. Because EPCA contains a specific definition for “general service lamp,” which is used mostly to define the scope of DOE's efficiency standards, NEMA warned that the proposed amendment would create inconsistencies between FTC and DOE regulations and sow confusion. NEMA also argued that the Commission does not have authority to amend the statutory definition of “general service lamp” because EPCA reserves such authority to the Secretary of Energy (42 U.S.C. 6291(30)(BB)(i)(IV)). NEMA acknowledged that the Commission has authority to require labeling for consumer products under 42 U.S.C. 6294(a)(6), but argued that, in exercising this power, the Commission should not use definitions inconsistent with EPCA.
Under EPCA, the Commission can require labeling for any consumer product if such labeling is “likely to assist consumers in making purchasing decisions.”
Consistent with this statutory direction, the modified proposal covers lamp types with wattages and light output similar to currently covered general service bulbs. The new labels will provide a means for consumers to compare the energy use, brightness, and other attributes of different bulb types and technologies commonly available on the market. Specifically, the modified labeling proposal applies to bulbs that: (1) Are rated at 30 watts or higher or produce 310 lumens or more; (2) have a medium, intermediate, candelabra, GU-10, or GU-24 base; and (3) do not meet the definition of “general service lamp.”
The proposal excludes bulb types for which labeling may not provide substantial benefit to consumers, including bulbs that use less than 30 watts and produce low light output, or bulbs not typically purchased by residential consumers. It also specifically excludes uncommon bulb shapes, lamp types with little market presence, and bulbs generally used for commercial applications. The proposed exclusions are: black light lamps, bug lamps, colored lamps, infrared lamps, left-hand thread lamps, marine lamps, marine signal service lamps, mine service lamps, sign service lamps, silver bowl lamps, showcase lamps, traffic signal lamps, G-shape lamps with diameter of 5 inches or more, and C7, M-14, P, RP, S, and T-shape lamps.
In addition to the labeling requirements, the proposal requires markings (
The Commission proposes a smaller, single label option [Figure 1] that manufacturers may use on package fronts for certain specialty use bulbs to help fit the label on small packages.
In seeking to expand coverage of the Lighting Facts label, the Commission does not propose altering the Rule's existing test procedure and reporting requirements. Under the current rule, manufacturers (or private labelers) must use DOE test procedures for lamp products covered by those DOE test procedures. If no existing DOE test procedure applies to a particular lamp, the Rule requires manufacturers to possess and rely upon a reasonable basis consisting of competent and reliable scientific tests and procedures substantiating the representation.
For bulbs not covered by the proposal (
Finally, consistent with NEMA's suggestions, the proposal does not alter the definition of “general service lamp.” Instead, the Commission proposes to create a new category of covered bulbs called “specialty consumer lamps” and identify the covered bulbs by shape, base, wattage, and lumen range. This approach will reduce confusion that may arise from changing the definition of “general service lamp,” which is also used in DOE's efficiency standards program. Finally, the Commission proposes a change to the definition of “fluorescent lamp ballast” to conform with a new DOE definition for those products.
The Commission seeks comment on all aspects of this proposal. In particular, comments should address whether labeling for “specialty consumer lamps” will help consumers make purchasing decisions and, if so, whether that benefit is outweighed by increased labeling costs. In addition, commenters should address whether the lower wattage limit should be 30 watts, or a different figure.
Seven energy-efficiency, environmental, and consumer advocacy organizations (#560957-00028) (“Joint Commenters”)
The Association of Home Appliance Manufacturers (AHAM) (#560957-00013), Whirlpool (#560957-00010), and BSH Home Appliance Corporation (BSH) (#560957-00007) urged the Commission to replace paper labeling with a publicly accessible online database. In support of this recommendation, these manufacturers reported that approximately two-thirds of consumers who purchased appliances in the prior year conducted online research prior to the purchase, and that more than 70% planned to do so for future purchases. Thus, the manufacturers concluded that having only online labels would be effective and sufficient. Whirlpool (#560957-00010) added that the FTC should create a public online version of the existing CCMS database, and expand it to consolidate FTC and DOE requirements. Whirlpool argued that label images should continue to be displayed on manufacturer and retailer Web sites, and noted that it currently provides electronic access to label images for all current products, until the product is declared obsolete. Similarly, Alliance (#560957-00011) questioned the necessity of paper labels in today's electronic age. Alliance supported use of the QR codes, but on a sign posted at point-of-sale instead of on a physical label.
This proposal should benefit consumers and retailers. Consumers will have access to a single comprehensive database at the DOE Web site containing label images for covered products. Online retailers will have access to digital labels for advertising, without submitting separate requests to manufacturers. Similarly, retailers that want to replace missing labels at the points-of-sale will be able to print replacements from the CCMS database.
The proposal should not create undue burdens on manufacturers. The Rule already requires manufacturers of most covered products to submit annual reports. DOE likewise requires manufacturers to make detailed electronic submissions through CCMS.
Because the proposed CCMS database would link to manufacturers' label Web pages, the Commission does not propose eliminating requirements related to such Web pages. Doing so would likely impose greater technical maintenance and coordination burdens on both DOE and manufacturers.
Finally, as explained above, the Commission does not propose abandoning physical labels at this time. Notwithstanding the growing availability of Internet access, physical labels, especially those displayed at the point-of-sale in stores, likely help a substantial number of consumers. The Commission recognizes the Internet's potential as a comprehensive source for energy consumption information, but not all consumers have online access, and not all those who do conduct online research before making purchase decisions. Moreover, even consumers who research products online may benefit from viewing the physical labels in the store.
The Rule currently permits manufacturers of refrigerators, dishwashers, and clothes washers to post the required EnergyGuide labels either using adhesive labels or hang
Like the Joint Commenters, three Western energy utilities recommended prohibiting hang tags.
Three manufacturers opposed an adhesive label-only requirement.
Manufacturers proposed several alternatives. As discussed in Section B, they recommended that the Commission abandon physical labels altogether. Arguing that physical labels are no longer relevant because consumers research product information online, they proposed that the Commission create an online database through which consumers can research products' energy efficiency.
However, manufacturers did not recommend prohibiting adhesive labels. Instead, they recommended retaining both the adhesive and hang tag options. Additionally, Whirlpool recommended requiring two strings for hang tags to reduce missing labels. AHAM proposed amending the Rule to allow hang tags on product exteriors, in addition to interiors.
The Commission proposes amending the Rule (Section 305.11(d)(2)) to require that hang tags be affixed to products using cable ties (
The Commission does not propose amending the Rule to allow hang tags to be affixed to products' exteriors because it is concerned about the heightened risk of detachment with exterior hang tags. The Commission prohibited exterior hang tags in 2007 to “minimize the chance that labels will become dislodged from products.”
Finally, the Commission does not propose amending the Rule to include additional provisions suggested by the comments. First, the Commission does not propose prescribing more specific types of adhesive labels. Absent evidence of widespread problems caused by deficient adhesion methods, the Commission is reluctant to prescribe additional specific label attachment requirements that would reduce flexibility and may impose costs. Still, manufacturers should remain mindful that labels “should be applied with an adhesive with an adhesion capacity sufficient to prevent their dislodgment during normal handling throughout the chain of distribution to the retailer or consumer.”
AHAM also took issue with the proposal's complexity. It noted that the Commission would have to allow for black and white labels because many boxes are not printed in color. It also indicated that the label may not be visible to consumers if the box is stacked in a way that obscures the label. These comments also noted that the label may not easily fit on boxes for smaller room air conditioners, some of which are about a foot high. AHAM argued that, were the Commission to require box labels, it should allow manufacturers to use an adhesive sticker rather than printing the label directly on the box. Finally, AHAM asked whether the label would have to appear in multiple languages if other information on the box appeared in languages other than English.
In contrast, the Joint Commenters (# 560957-00015) urged the Commission to require labels on both boxes and the products themselves. In support, they cited store visit results indicating that retailers display units as often inside the box as outside. The Joint Commenters also recommended that the Commission follow the same approach for compact refrigerators and water heaters, noting that many stores they visited displayed these products in boxes while others displayed them only out of the box.
Finally, AHAM requested that the Commission revise the label to require a new efficiency rating disclosure, noting that DOE has changed the energy efficiency metric for room air conditioners from energy efficiency ratio (EER) to a combined energy efficiency ratio (CEER).
Under the proposal, manufacturers would have the flexibility to choose a background color for the label to avoid requiring some manufacturers to redesign their boxes. Manufacturers could also use stickers in lieu of printing the label on the box itself. This would allow them to update their labels in response to test procedure or range changes without creating new packaging. With sufficient lead-time, manufacturers should be able to incorporate the label on packaging with little or no additional burden.
Accordingly, commenters should address whether this approach raises complications for routine label revisions due to range changes, cost updates, or test procedure amendments. Also, the Commission seeks comment on the amount of time necessary to effect these changes and the efficacy and burdens of requiring the label on the box.
The Commission is not proposing to require labels on both the product and the box. The burden of requiring physical labels in multiple locations likely outweighs the benefits from such additional disclosures, particularly given new provisions increasing the labels' availability to consumers online.
Finally, the Commission proposes two changes related to recent DOE regulatory actions. First, it proposes to change the room air conditioner label to replace EER ratings with CEER ratings consistent with upcoming DOE changes for these products. According to commenters, the differences between EER and CEER should be minor. Therefore, the Commission only proposes a simple name change in Section 305.7 and sample label 4, which change the label's capacity description for these products. Second, the Commission proposes requiring EnergyGuide labels for portable air conditioners, in light of a recent DOE proposal to designate portable air conditioners as covered products under EPCA.
The proposed label follows the EnergyGuide label format, consistent with other products displayed in showrooms, such as refrigerators and clothes washers.
Finally, the Commission does not propose including disclosures required by the CEC, which include energy information at multiple speeds. Such information is likely to complicate the label by providing three sets of disclosures for CFM, energy cost, and energy use. In addition, the label's current high-speed disclosures should provide adequate information for consumers to compare the relative energy cost and performance of competing fans.
The Joint Commenters urged the Commission to consolidate the comparability ranges.
According to the Joint Commenters, many consumers consider refrigerators with different configurations (and likely different features) when making purchasing decisions. To support this assertion, the commenters pointed to data demonstrating that, in 2012, 40% of the visitors to Consumer Reports' online refrigerator ratings reviewed multiple refrigerator-freezer configurations. The Joint Commenters also reasoned that those who examined only one configuration probably considered models with, and without, through-the-door ice dispensers, and may have looked at an additional configuration on a subsequent visit. In addition, the Joint Commenters pointed to AHAM information demonstrating that more than half of side-by-side refrigerator-freezer owners buy replacement units with a different configuration. The commenters contended that this was probably a conservative estimate because it does not include owners who bought similarly configured replacement units with different features. Finally, the Joint Commenters submitted the results of a survey of Earthjustice members showing that more than two thirds of respondents indicated that a label that compared across subcategories would be more likely to assist them in making their purchasing decision.
Finally, the Joint Commenters further argued that, even if some consumers initially limit themselves to a certain product subcategory, an EnergyGuide label illustrating the energy cost range over all subcategories may spur them to consider other configurations. They contend that, although the ENERGY STAR program continues to use separate categories for rating products, “the mere fact that ENERGY STAR labels refrigerators in a way that obscures the impacts of configurations and features does not justify” the maintenance of those categories for EnergyGuide labeling.
Specifically, the Commission proposes to consolidate the ranges for refrigerators into three categories: automatic defrost refrigerator-freezers (currently Appendices A4-A8), manual or partial manual refrigerators and refrigerator-freezers (currently Appendices A2-A3, which cover mostly small-sized models), and refrigerators with no freezer (currently Appendix A1). The proposed approach would consolidate ranges for automatic defrost models purchased by the vast majority of residential consumers, while maintaining separate categories for less common models.
The Commission seeks comment on this proposal. Among other things, comments should address whether the consolidation of range categories would impact the DOE and EnergyStar programs, which continue to follow DOE's multiple configuration categories.
In its February 6, 2013 Notice, the Commission tied implementation of the new labeling requirements for all heating and cooling equipment (including products not subject to uniform standards) to the DOE compliance dates for the regional standards.
In addition, on April 24, 2014, the Court approved a settlement in the DOE litigation, which vacates and remands DOE's regional standards for non-weatherized natural gas and mobile home furnaces and set a two-year time table for DOE to propose new standards. The settlement does not affect other DOE standards, including the regional standards for split system and single package central air conditioners scheduled to become effective on January 1, 2015. However, as part of the settlement, DOE has agreed to issue a policy statement establishing an 18-month enforcement grace period for any air conditioner units manufactured before January 1, 2015.
In addition, AHRI (#563707-00010) raised concerns about the required capacity disclosure on the new labels. It explained that, for split-system air conditioners, capacity depends on the actual condenser-coil combination installed on site. The EnergyGuide label only appears on the condensing unit. Because manufacturers cannot predict which coil will be paired with a particular condenser, they cannot predict the system's capacity rating. Similarly, for oil furnaces, the unit's ultimate capacity depends on the input set by the installer.
Thus, in AHRI's view, the inclusion of capacity information on these products is unnecessary and could mislead consumers. In lieu of capacity ratings, AHRI suggested that the FTC allow manufacturers to print basic model numbers on their EnergyGuide labels, which can be used to access cost information on DOE's database.
In response to AHRI's capacity concerns, the Commission proposes eliminating capacity on EnergyGuide labels for heating and cooling
In contrast, Southern Cal Edison (#560957-00008) and PG&E (#560957-00009) supported the inclusion of such codes on the label because they would facilitate innovative practices for communicating useful consumer information to help purchasing decisions. In their view, QR codes would complement a growing market trend and allow consumers to conduct “on the go” research with their smart phones. It would also provide an opportunity for utility programs and third party rebate programs to inform interested buyers about rebates for efficient products.
The comments also offered differing views on label information for full fuel cycle and greenhouse gas impacts. PG&E urged the FTC to work with DOE to inform consumers about the broad energy impacts and greenhouse gas emissions of covered products and to display such information on the EnergyGuide label. In contrast, Whirlpool asserted that consumers do not find data on greenhouse gases and full fuel cycle information relevant to their purchase decision.
The FTC staff will continue to consider full-fuel cycle and greenhouse gas information for consumers and keep track of DOE's efforts to incorporate full-fuel cycle analysis into their decisionmaking.
NEMA argued that a bilingual label will not fit on all packages and, as a result, a mandatory, triggered bilingual label could discourage manufacturers from providing any bilingual information. In addition, NEMA suggested that a bilingual label may not be necessary for energy labeling because the FTC-required label displays data mostly in numbers.
The comments offered no evidence that packages for products labeled with the FTC's energy labels convey consumer information principally in a language other than English. Although some packages present information in both English and another language, it appears that English remains the principal language on packaging. Additionally, the prominence of numerical disclosures on the energy labels (
The Joint Commenters also recommended an increase in the size and prominence of the arrow indicating the model's relative location along the comparability range. The arrow denotes placement on the range and allows consumers to quickly gauge whether a model is efficient compared to similar models.
In lieu of the current five-year schedule, the efficiency groups recommended that the Commission update ranges whenever: (1) Multiple new products enter the market in a product subcategory not included in an existing range category, (2) more efficient products appear on the market, and (3) efficiency standards or ENERGY STAR specifications change. In the absence of such thresholds, the Joint Commenters suggested a three-year schedule for most products and a two-year schedule for those with rapidly changing efficiencies and quicker sell-through periods. In addition, to help consumers compare labels bearing different range information, the Joint Commenters recommended the use of the transitional label recently adopted for refrigerators and clothes washers to address range and cost changes.
In contrast, industry commenters supported the current approach. AHAM emphasized the need to minimize frequent label changes because inconsistent cost and range information can lead to consumer confusion and erode consumer confidence in the label. AHAM agreed with the Commission that a five-year schedule appropriately balances the need for consistent disclosures and the need for updates, while minimizing the burdens associated with frequent changes. AHRI argued that any revisions at this point would be premature, because the current schedule has been in place for only a few years. According to AHRI, industry members and consumers have not conveyed any significant concerns to its members about the EnergyGuide label ranges. AHRI further asserted that consumers recognized that the EnergyGuide label serves primarily as a comparative tool. In its view, the label's comparative information does not
The current five-year interval ranges is consistent with past trends in market data. Over the years, model energy use has not always changed significantly from year to year across all product types and the product range endpoints have not always moved toward higher efficiency levels from year to year.
In addition, frequent fuel cost updates for the label can significantly impact label information during transition periods, making it difficult for consumers to compare new and old labels. Frequent fuel cost updates not only alter the range information but also the product's energy cost (the label's primary energy disclosure), and can inhibit comparisons with older labeled products generated with previous fuel rates.
Though the Commission does not propose to alter the current schedule, the Rule gives the Commission discretion to change ranges and fuel rates more frequently. If parties identify ranges or fuel rate information that should be updated before the five-year period ends, they should alert the Commission so that it may consider whether to update the range.
Finally, the Commission declines to adopt the recommendation to change ranges whenever a more efficient product enters the market, whenever DOE standards or test procedures change, or whenever a new product subcategory (
The Joint Commenters further opined that compliance with such a requirement is feasible. They argued that retailers would not face extraordinary obstacles matching EnergyGuide labels with the intended products, noting that retailers already manage point-of-sale materials for specific products, such as price and rebate information and Energy Star labels. Additionally, the Joint Commenters observed during site visits that some retailers appear to attach, reattach, or reprint missing labels. Indeed, the Joint Commenters argued that retailers are better situated than manufacturers to remedy lost, missing, or non-compliant labels. In addition, citing a “preliminary analysis” of their investigative results, they argued that the identity of the retailer is most closely correlated with the rate of label compliance.
AHAM also encouraged the Commission to address retailer responsibility, although it stopped short of supporting a new mandate (#563707-00003). AHAM explained that manufacturers lose control over products after they leave the factory, and that retailers own the products they sell to consumers. Accordingly, AHAM argued that manufacturers should not be held responsible for missing labels on showroom floors.
Retailers, however, can play an important role in ensuring that labels appear on covered products at the points-of-sale. Even if retailers do not create the labels, they can identify missing or obscured labels in their showrooms and replace them. Moreover, although label design and attachment improvements can raise the rate of label presence, they cannot guarantee it.
It is premature to impose these costs and incur these risks when better label requirements and greater availability of online labels may alleviate the problem. The Commission, therefore, seeks further comment, particularly on improved label design and other approaches that could reduce the incidence of missing labels.
These amendments do not cover marketplace Web sites that serve as platforms for facilitating online product purchase by performing functions such as hosting sellers' advertising, matching buyers' searches to sellers' products, and processing payment and shipment directions.
The Joint Commenters also requested that the Commission clarify that (i) the Rule applies to sellers who list covered products for sale on Web site catalogs, but do not take physical possession of products, and (ii) the Rule's term “catalog” includes: online product listings that require an additional click or mouse-over to reveal the product's retail price; product Web pages that allow the consumer to select different product options, such as color, before moving on to complete the purchase; and marketplace Web site listings that contain the terms of sale, retail price, and instructions for ordering, but that require consumers to click through to another Web site to complete the order.
The Joint Commenters acknowledged the small difference in energy costs between similar dryer models. However, they noted recent DOE amendments associated with an updated test procedure suggest a broader range of energy use among dryers than previously thought. In addition, the adoption of heat-pump dryers will lead to significantly more efficient models in the future. In both absolute and relative terms, they predicted efficiency differences among clothes dryer models will be greater than efficiency differences among existing subcategories for televisions and refrigerators.
Alliance Laundry Systems (#563707-00012) disagreed, arguing that the FTC should not require labels for a covered product simply because it uses large amounts of energy. Alliance explained that the range of energy use among competing dryers is narrow. Thus, labels would not aid consumer purchasing decisions. The Alliance also noted that the high purchase price for the new heat-pump clothes dryers will discourage consumers from purchasing such products even if they are more efficient than other models.
Absent meaningful variation in energy usage, the Commission doubts that labeling would significantly aid consumer choices. Although some comments suggest that labels could induce consumers to hang dry their
The Commission proposes two minor changes related to plumbing products. First, it proposes amendments to clarify that retail Web sites may hyperlink to flow rate information for the covered plumbing products they sell. Recent amendments to Section 305.20 allow online retailers to use a hyperlink to connect consumers to EnergyGuide and Lighting Facts labels for specific products, but do not specify how online sellers may link to required plumbing disclosures.
Second, the Commission proposes routine conforming changes to the Rule in response to DOE test procedure changes. On October 23, 2013, DOE announced changes to the testing procedures for residential plumbing products and amended some product definitions.
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before August 18, 2014. Write “Energy Labeling Regulatory Review (16 CFR Part 305) (Matter No. R611004)” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, such as anyone's Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which is . . . privileged or confidential,” as discussed in § 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you have to follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c). Your comment will be kept confidential only if the FTC General Counsel, in his or her sole discretion, grants your request in accordance with the law and the public interest.
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at
If you prefer to file your comment on paper, mail your comment to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex B), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor, Suite 5610 (Annex B), Washington, DC 20024. If possible, submit your paper comment to the Commission by courier or overnight service.
Visit the Commission Web site at
Because written comments appear adequate to present the views of all interested parties, the Commission has not scheduled an oral hearing regarding these proposed amendments. Interested parties may request an opportunity to present views orally. If such a request is made, the Commission will publish a document in the
The current Rule contains recordkeeping, disclosure, testing, and reporting requirements that constitute information collection requirements as defined by 5 CFR 1320.3(c), the definitional provision within the Office of Management and Budget (OMB) regulations that implement the Paperwork Reduction Act (PRA). OMB has approved the Rule's existing information collection requirements through May 31, 2017 (OMB Control No. 3084 0069). The proposed amendments make changes in the Rule's labeling requirements that will increase the PRA burden as detailed below.
Pursuant to Section 3506(c)(2)(A) of the PRA, the FTC invites comments on: (1) Whether the proposed information collection is necessary, including whether the information will be practically useful; (2) the accuracy of our burden estimates, including whether the methodology and assumptions used are valid; (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. All comments should be filed as prescribed in the
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires that the Commission provide an Initial Regulatory Flexibility Analysis (IRFA) with a proposed rule and a Final Regulatory Flexibility Analysis (FRFA), if any, with the final rule, unless the Commission certifies that the rule will not have a significant economic impact on a substantial number of small entities.
The Commission does not anticipate that the proposed rule will have a significant economic impact on a substantial number of small entities. The Commission recognizes that some of the affected manufacturers may qualify as small businesses under the relevant thresholds. However, the Commission does not expect that the economic impact of the proposed amendments will be significant.
The Commission estimates that the amendments will apply to about 75 light bulb manufacturers and an additional 150 online and paper catalog sellers of covered products. The Commission expects that approximately 150 qualify as small businesses.
Accordingly, this document serves as notice to the Small Business Administration of the FTC's certification of no effect. To ensure the accuracy of this certification, however, the Commission requests comment on whether the proposed rule will have a significant impact on a substantial number of small entities, including specific information on the number of entities that would be covered by the proposed rule, the number of these companies that are small entities, and the average annual burden for each entity. Although the Commission certifies under the RFA that the rule proposed in this document would not, if promulgated, have a significant impact on a substantial number of small entities, the Commission has determined, nonetheless, that it is appropriate to publish an IRFA in order to inquire into the impact of the proposed rule on small entities. Therefore, the Commission has prepared the following analysis:
The Commission is proposing expanded product coverage and additional improvements to the Rule to help consumers in their purchasing decisions for high efficiency products.
The objective of the rule is to improve the effectiveness of the current labeling program. The legal basis for the Rule is the Energy Policy and Conservation Act (42 U.S.C. 6292
Under the Small Business Size Standards issued by the Small Business Administration, appliance manufacturers qualify as small businesses if they have fewer than 1,000 employees (for other household appliances the figure is 500 employees). Catalog sellers qualify as small businesses if their sales are less than $8.0 million annually. The Commission estimates that there are approximately 150 entities subject to the proposed rule's requirements that qualify as small
The changes under consideration would slightly increase reporting or recordkeeping requirements associated with the Commission's labeling rules as discussed above. The amendments likely will increase compliance burdens by extending the labeling requirements to new types of light bulbs and air conditioners. The Commission assumes that the label design change will be implemented by graphic designers.
The Commission has not identified any other federal statutes, rules, or policies that would duplicate, overlap, or conflict with the proposed rule. The Commission invites comment and information on this issue.
The Commission seeks comment and information on the need, if any, for alternative compliance methods that, consistent with the statutory requirements, would reduce the economic impact of the rule on small entities. For example, in proposing to extend the bulb coverage, the Commission is currently unaware of the need to adopt any special provision for small entities to be able to take advantage of the proposed extension or exemption, where applicable. However, if such issues are identified, the Commission could consider alternative approaches such as extending the effective date of these amendments for catalog sellers to allow them additional time to comply beyond the labeling deadline set for manufacturers. Nonetheless, if the comments filed in response to this document identify small entities that are affected by the rule, as well as alternative methods of compliance that would reduce the economic impact of the rule on such entities, the Commission will consider the feasibility of such alternatives and determine whether they should be incorporated into the final rule.
Written communications and summaries or transcripts of oral communications respecting the merits of this proceeding, from any outside party to any Commissioner or Commissioner's advisor, will be placed on the public record. See 16 CFR 1.26(b)(5).
Advertising, Energy conservation, Household appliances, Labeling, Reporting and recordkeeping requirements.
For the reasons discussed above, the Commission proposes to amend part 305 of title 16, Code of Federal Regulations, as follows:
42 U.S.C. 6294.
(j)
(r)
(z)
(1) Any lamp that—
(i) Is not included under the definition of general service lamp in this part;
(ii) Has a lumen range between 310 lumens and no more than 2,600 lumens or a rated wattage between 30 and 199;
(iii) Has one of the following bases:
(A) A medium screw base;
(B) An intermediate screw base;
(C) A candelabra screw base;
(D) A GU-10 base; or
(E) A GU-24 base; and
(iv) Is capable of being operated at a voltage range at least partially within 110 and 130 volts.
(2)
(i) Vibration-service lamps as defined at 42 U.S.C. 6291(30)(AA);
(ii) Rough service lamps as defined at 42 U.S.C. 6291(30)(X);
(iii) Appliance lamps as defined at 42 U.S.C. 6291(30)(T);
(iv) Plant light lamps; and
(iv) Shatter-resistant lamps (including a shatter-proof lamp and a shatter-protected lamp) as defined in 42 U.S.C. 6291(30)(Z).
(3)
(i) A black light lamp;
(ii) A bug lamp;
(iii) A colored lamp;
(iv) An infrared lamp;
(v) A left-hand thread lamp;
(vi) A marine lamp;
(vii) A marine signal service lamp;
(viii) A mine service lamp;
(ix) A sign service lamp;
(x) A silver bowl lamp;
(xi) A showcase lamp;
(xii) A traffic signal lamp;
(xiii) A G-shape lamp with diameter of 5 inches or more;
(xiv) A C7, M-14, P, RP, S, or T shape lamp.
(d)
(f)
(a) * * *
(3) This section does not require reports for general service light-emitting diode (LED or OLED) lamps or specialty consumer lamps.
(c)
(d)
(2)
(3)
(f)
(1) Headlines and texts, as illustrated in the prototype and sample labels in appendix L to this part.
(2) Name of manufacturer or private labeler shall, in the case of a corporation, be deemed to be satisfied only by the actual corporate name, which may be preceded or followed by the name of the particular division of the corporation. In the case of an individual, partnership, or association, the name under which the business is conducted shall be used. Inclusion of the name of the manufacturer or private labeler is optional at the discretion of the manufacturer or private labeler.
(3) The model's basic model number.
(4) The annual fuel utilization efficiency (AFUE) for furnace models as determined in accordance with § 305.5.
(5) Ranges of comparability consisting of the lowest and highest annual fuel utilization efficiency (AFUE) ratings for all furnaces of the model's type consistent with the sample labels in appendix L.
(6) Placement of the labeled product on the scale shall be proportionate to the lowest and highest annual fuel utilization efficiency ratings forming the scale.
(7) The following statement shall appear in bold print on furnace labels adjacent to the range(s) as illustrated in the sample labels in appendix L: For energy cost info, visit
(8) The following statement shall appear at the top of the label as illustrated in the sample labels in appendix L: Federal law prohibits removal of this label before consumer purchase.
(9) No marks or information other than that specified in this part shall appear on or directly adjoining this label except that:
(i) A part or publication number identification may be included on this label, as desired by the manufacturer. If a manufacturer elects to use a part or publication number, it must appear in the lower right-hand corner of the label and be set in 6-point type or smaller;
(ii) The energy use disclosure labels required by the governments of Canada or Mexico may appear directly adjoining this label, as desired by the manufacturer;
(iii) The manufacturer may include the ENERGY STAR logo on the label for certified products in a location consistent with the sample labels in appendix L. The logo must be no larger than 1 inch by 3 inches in size. Only manufacturers that have signed a Memorandum of Understanding with the Department of Energy or the Environmental Protection Agency may add the ENERGY STAR logo to labels on qualifying covered products; such manufacturers may add the ENERGY STAR logo to labels only on those covered products that are contemplated by the Memorandum of Understanding.
(10) Manufacturers of boilers shipped with more than one input nozzle to be installed in the field must label such boilers with the AFUE of the system when it is set up with the nozzle that results in the lowest AFUE rating.
(11) Manufacturers that ship out boilers that may be set up as either steam or hot water units must label the boilers with the AFUE rating derived by conducting the required test on the boiler as a hot water unit.
(12) Manufacturers of oil furnaces must label their products with the AFUE rating associated with the furnace's input capacity set by the manufacturer at shipment. The oil furnace label may also contain a chart, as illustrated in sample label 9B in appendix L, indicating the efficiency rating at up to three additional input capacities offered by the manufacturer. Consistent with paragraph (f)(9)(iii) of this section, labels for oil furnaces may include the ENERGY STAR logo only if the model qualifies for that program on all input capacities displayed on the label.
(a)
(i) Headlines, including the title “EnergyGuide,” and text as illustrated in the sample labels in Appendix L to this part;
(ii) The product's estimated yearly energy cost based on 6 hours use per day and 12 cents per kWh;
(iii) The product's airflow at high speed expressed in cubic feet per minute and determined pursuant to § 305.5 of this part;
(iv) The product's energy use at high speed expressed in watts and determined pursuant to § 305.5 of this part as indicated in the sample label in appendix L of this part;
(v) The statement “Your cost depends on rates and use”;
(vi) The statement “All estimates at high speed, excluding lights”;
(vii) The statement “the higher the airflow, the more air the fan will move;”
(viii) The statement “Airflow Efficiency: __Cubic Feet Per Minute Per Watt””;
(ix) The address
(x) For fans fewer than 49 inches in diameter, the label shall display a cost range for 36″ to 48″ ceiling fans of $2 to $53.”;
(xi) For fans 49 inches or more in diameter, the label shall display a cost range for 49″ to 60″ ceiling fans of $3 to $29.”; and
(xii) The ENERGY STAR logo as illustrated on the ceiling fan label illustration in Appendix L for qualified products, if desired by the manufacturer. Only manufacturers that have signed a Memorandum of Understanding with the Department of Energy or the Environmental Protection Agency may add the ENERGY STAR logo to labels on qualifying covered products; such manufacturers may add the ENERGY STAR logo to labels only on those products that are covered by the Memorandum of Understanding;
(2)
(3)
(4)
(b)
(c)
(2)
(i) The principal display panel of the product package shall be labeled clearly and conspicuously with the following information consistent with the Prototype Label __ in Appendix L:
(A) The light output of each lamp included in the package, expressed as “Brightness” in average initial lumens rounded to the nearest five; and
(B) The estimated annual energy cost of each lamp included in the package, expressed as “Estimated Energy Cost” in dollars and based on usage of 3 hours per day and 11 cents ($0.11) per kWh.
(C) The life, as defined in § 305.2(w), of each lamp included in the package, expressed in years rounded to the nearest tenth (based on 3 hours operation per day);
(ii) If the lamp contains mercury, the principal display panel shall contain the following statement:
“Contains Mercury For more on clean up and safe disposal, visit
The manufacturer may also print an “Hg[Encircled]” symbol on package after the term “Contains Mercury.”
(iii) If the lamp contains mercury, the lamp shall be labeled legibly on the product with the following statement: “Mercury disposal:
(4)
(i) The Lighting Facts information shall be set off in a box by use of hairlines and shall be all black or one color type, printed on a white or other neutral contrasting background whenever practical.
(ii) All information within the Lighting Facts label shall utilize:
(A) Arial or an equivalent type style;
(B) Upper and lower case letters;
(C) Leading as indicated in Prototype Label __ in appendix L;
(D) Letters that never touch;
(E) The box and hairlines separating information as illustrated in Prototype Labels __ in appendix L; and
(F) The minimum font sizes and line thicknesses as illustrated in Prototype Label __ in appendix L.
(4)
(d) For lamps that do not meet the definition of general service lamp or specialty consumer lamp, manufacturers and private labelers have the discretion to label with the Lighting Facts label as long as they comply with all requirements applicable to specialty consumer lamps.
(f)(1) The required disclosures of any covered product that is a general service lamp or specialty consumer lamp shall be measured at 120 volts, regardless of the lamp's design voltage. If a lamp's design voltage is 125 volts or 130 volts, the disclosures of the wattage, light output, energy cost, and life ratings shall in each instance be:
(4) For any covered product that is a general service lamp or specialty consumer lamp and operates at discrete, multiple light levels (
(a) * * *
(1) * * *
(ii) Products not required to bear EnergyGuide or Lighting Facts labels. All Web sites advertising covered showerheads, faucets, water closets, urinals, general service fluorescent lamps, fluorescent lamp ballasts, and metal halide lamp fixtures must include the following disclosures for each
Food and Drug Administration, HHS.
Advance notice of proposed rulemaking; reopening of comment period.
The Food and Drug Administration (FDA or we) is reopening the comment period for the advance notice of proposed rulemaking that appeared in the
Submit either electronic or written comments by August 18, 2014.
You may submit comments, identified by Agency name, Docket No. FDA-2013-N-0590 and/or Regulatory Information Number (RIN) 0910-AG97, by any of the following methods:
Submit electronic comments in the following way:
•
Submit written submissions in the following way:
•
Ted Elkin, Center for Food Safety and Applied Nutrition (HFS-008), Food and Drug Administration, 5100 Paint Branch Pkwy, College Park, MD 20740, 240-402-2428; or April Hodges, Center for Veterinary Medicine (HFV-230), Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855, 240-276-9237.
In the
We have received a request for a 60-day extension of the comment period for the advance notice of proposed rulemaking. The request conveyed concern that the 75-day comment period did not allow sufficient time to develop a meaningful or thoughtful response to the advance notice of proposed rulemaking particularly in light of other FSMA-related rulemakings for which the Agency is also requesting comments.
We have considered the request and are reopening the comment period for the advance notice of proposed rulemaking for 60 days, until August 18, 2014. We believe that reopening the comment period an additional 60 days allows adequate time for interested persons to submit comments without significantly delaying rulemaking on these important issues.
Interested persons may submit either electronic comments regarding this document to
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 and requests for a public hearing must be received by September 16, 2014.
Send submissions to: CC:PA:LPD:PR (REG-121542-14), Room 5203, Internal Revenue Service, P.O. 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-121542-14), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC, or sent electronically via the Federal eRulemaking Portal at
Concerning submission of comments, Oluwafunmilayo (Funmi) Taylor, (202) 317-6901; concerning the proposed regulations, A M Gulas, (202) 317-6834 (not toll-free numbers).
The temporary regulations in the Rules and Regulations section of this issue of the
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. The IRS has also 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 do not impose an information collection on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Therefore, a regulatory flexibility analysis is not required. Pursuant to section 7805(f) of the Internal Revenue Code, the IRS will submit the proposed regulations to the Chief Counsel for Advocacy of the Small Business Administration for comments about the regulations' impact on small business.
Before these proposed regulations are adopted as final, the IRS will consider any written (signed original and 8 copies) or electronic comments timely submitted. The IRS requests comments on all aspects of these proposed regulations. All comments will be available for public inspection and copying. The IRS will schedule a public meeting if one is requested, in writing, by a person who submits written comments. If the IRS does schedule a public hearing, the IRS will publish notice of the date, time, and place for the public hearing in the
The principal author of these regulations is A M Gulas of the Office of Associate Chief Counsel (Procedure and Administration).
Employment taxes, estate taxes, excise taxes, gift taxes, income taxes, penalties, reporting and recordkeeping requirements.
Accordingly, 26 CFR part 301 is amended as follows:
26 U.S.C. 7805 * * *
(b) * * *
(3) [The text of proposed § 301.7602-1(b)(3) is the same as the text of § 301.7602-1T(b)(3) published elsewhere in this issue of the
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to add twenty four new fireworks events at various locations in the Sector Columbia River Captain of the Port zone. The Coast Guard also proposes to correct the location of some existing fireworks events in the Sector Columbia River Captain of the Port zone. In addition, the Coast Guard proposes to change the format of the existing regulation by using a table to list each fireworks. When these safety zones are activated and subject to enforcement, this rule would limit the movement of vessels within the established firework display areas. These additional safety zones and corrections to existing safety zones are necessary to prevent injury and to protect life and property of the maritime public from hazards associated with fireworks displays.
Comments and related material must be received by the Coast Guard on or before July 18, 2014.
Requests for public meetings must be received by the Coast Guard on or before June 25, 2014.
You may submit comments identified by docket number USCG-2014-xxxx using any one of the following methods:
(1)
(2)
(3)
See the “Public Participation and Request for Comments” portion of the
If you have questions on this rule, call or email LTJG Ian McPhillips, Waterways Management Division, Marine Safety Unit Portland, Coast Guard; telephone 503-240-9319, email
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online at
To submit your comment online, go to
If you submit your comments by mail or hand delivery, submit them in an unbound format, no larger than 8
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
We do not plan on holding a public meeting. But you may submit a request for one, using one of the methods specified under
The legal basis for these proposed regulations is 33 U.S.C. 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; Public Law 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1 which collectively authorize the Coast Guard to establish regulatory safety zones for safety and environmental purposes.
These proposed regulations are necessary to promote the safety of life on navigable waterways during various fireworks events located within the Captain of the Port Sector Columbia River zone.
Fireworks displays create hazardous conditions for the maritime public because of the large number of vessels that congregate near the displays, as well as the noise, falling debris, and explosions that occur during the event. Because fireworks discharge sites can pose a hazard to the maritime public, these proposed regulations are necessary in order to restrict vessel movement and reduce vessel congregation in the proximity of the fireworks discharge sites. The proposed corrections to the locations of some of the fireworks events listed in 33 CFR 165.1315 as well as the additional 24 safety zones proposed in this NPRM would be implemented to help ensure the safe navigation of maritime traffic in the Sector Columba River Area of Responsibility during fireworks displays.
This rule also proposes to amend the following fireworks displays into a table format and update some event positions in order to accurately reflect the coordinates of the fireworks displays listed in 33 CFR 165.1315:
This rule proposes to add twenty four new fireworks display locations, and proposes to change the title of 33 CFR 165.1315 to “
This rule proposes to add the following fireworks displays:
These safety zones will extend on and under the waters, 450 yards from the radius of the launch site described above. This zone size allows for the use of up to a 16″ mortar shell in annual fireworks displays. These zones are nominal in size and are typically positioned in areas which allow for transit around the zone. Thus, these zones have an inconsequential impact on the majority of waterway users. These zones are also short in duration and waterway users will be permitted to enter or transit through the zone when deemed safe by the on-scene patrol commander.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders. The Coast Guard bases this finding on the fact that the safety zones listed will be in place for a limited period of time and are minimal in duration.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered the impact of this proposed rule on small entities. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule will not have a significant economic impact on a substantial number of small entities.
(1) This rule may affect the following entities, some of which may be small entities: The owners and operators of vessels intending to operate in the area covered by the safety zone. The rule will not have a significant economic impact on a substantial number of small entities because the safety zones will only be in effect for a limited period of time. Additionally, vessels can still transit through the zone with the permission of the Captain of the Port. Before the effective period, we will publish advisories in the Local Notice to Mariners available to users of the river. Maritime traffic will be able to schedule their transits around the safety zone.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
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 proposed 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
This proposed 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 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. We have analyzed this proposed rule under that Order and determined that this rule 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 proposed rule would not result in such expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed 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 proposed rule under Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination With Indian Tribal Governments, because it would 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 proposed rule is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed 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 made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves the amendment to existing safety zones to reflect the correct position of the fireworks launch location and the addition of safety zones in 33 CFR 165.1315. This rule is categorically excluded from further review under paragraph 34(g) of Figure 2-1 of the Commandant Instruction. A preliminary environmental analysis checklist supporting this determination 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 proposes to amend 33 CFR Part 165 as follows:
33 U.S.C. 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) Safety Zones. The following areas are designated safety zones:
All waters of the Columbia River and its tributaries. All waters of the Siuslaw River, Yaquina River, Umpqua River as well as Washington and Oregon coasts, extending to a 450 yard radius with a 50 yard variation from the following launch sites:
(b) Special requirements. Fireworks barges or launch sites on land used in locations stated in this rule shall display a sign. The sign will be affixed to the port and starboard side of the barge or mounted on a post 3 feet above ground level when on land and in close proximity to the shoreline facing the water labeled “FIREWORKS—DANGER—STAY AWAY.” This will provide on-scene notice that the safety zone is, or will, be enforced on that day. This notice will consist of a diamond shaped sign, 4 foot by 4 foot, with a 3 inch orange retro-reflective border. The word “DANGER' shall be 10 inch black block letters centered on the sign with the words “FIREWORKS” and “STAY AWAY” in 6 inch black block letters placed above and below the word “DANGER” respectively on a white background. An on-scene patrol vessel may enforce these safety zones at least
(c) Notice of enforcement. These safety zones will be activated and thus subject to enforcement, under the following conditions: The Coast Guard must receive and approve a marine event permit for each fireworks display and then the Captain of the Port will cause notice of the enforcement of these safety zones to be made by all appropriate means to provide notice to the affected segments of the public as practicable, in accordance with 33 CFR 165.7(a). The Captain of the Port will issue a Local Notice to Mariners notifying the public of activation and suspension of enforcement of these safety zones. Additionally, an on-scene Patrol Commander may be appointed to enforce the safety zones by limiting the transit of non-participating vessels in the designated areas described above.
(d) Regulations. In accordance with the general regulations in 33 CFR part 165, subpart C, no vessel operator may enter, transit, moor, or anchor within this safety zone, except for vessels authorized by the Captain of the Port or Designated Representative.
(e) Authorization. All vessel operators who desire to enter the safety zone must obtain permission from the Captain of the Port or Designated Representative by contacting either the on-scene patrol craft on VHF Ch 13 or Ch 16 or the Coast Guard Sector Columbia River Command Center via telephone at (503) 861-6211.
(f) Enforcement period. This rule will be enforced at least 1 hour before and 1 hour after the duration of the event each day a barge or launch site with a “FIREWORKS—DANGER—STAY AWAY” sign is located within any of the above designated safety zone locations and meets the criteria established in paragraphs (a), (b), and (c).
(g) Contact information. Questions about safety zones and related events should be addressed to COMMANDER (spw), MARINE SAFETY UNIT PORTLAND, Attention: Waterways Management Division, 6767 N. Basin Ave, Portland, OR 97217-3992.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to modify several aspects of the safety and security zones within the Sector Jacksonville Captain of the Port Zone. This action is necessary to consolidate, clarify, and otherwise modify safety and security zone regulations to eliminate unnecessary regulations and better meet the safety and security needs of the Ports of Jacksonville, Fernandina, and Canaveral. This action would modify existing safety and security zones; establish safety zones governing port closures in the event of a natural and other disasters; and remove safety and security zones.
Comments and related material must be received by the Coast Guard on or before July 9, 2014.
A public meeting will be held on June 23, 2014 at 10 a.m. at USCG Sector Jacksonville and on June 25, 2014 at 10:30 a.m. at Inter-Agency Maritime Operations Center in Cape Canaveral, FL.
You may submit comments identified by docket number using any one of the following methods:
(1)
(2)
(3)
If you have questions on this rule, call or email Commander Alisa Praskovich, Sector Jacksonville Prevention Department, Coast Guard; telephone (904) 564-7549, email
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted without change to
If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation. You may submit your comments and material online at
To submit your comment online, go to
If you submit your comments by mail or hand delivery, submit them in an unbound format, no larger than 8
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review a Privacy Act notice regarding our public dockets in the January 17, 2008, issue of the
A public meeting will be held on June 23, 2014 at 10 a.m. at USCG Sector Jacksonville and on June 25, 2014 at 10:30 a.m. at Inter-Agency Maritime Operations Center in Cape Canaveral, FL. We plan to post the minutes of the meetings in the docket. For information on facilities or services for individuals with disabilities or to request special assistance at the public meeting, contact the person named in the
In 1994, the Coast Guard published a safety zone around firework barges between the Hart and Acosta Bridges within the Port of Jacksonville. As of 2008, there are 22 special local regulations listed under 33 CFR 100.701, which establish a 500-yard regulated area around various barges for firework display events. This regulatory change will revise the current regulations to add safety zone regulations regarding natural and other disasters port closures, as well as safety zones for all fire work displays.
The legal basis for the rule is the Coast Guard's authority to establish regulated navigation areas and limited access areas: 33 U.S.C. 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, 160.5; Public Law 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
The purpose of these regulations are to ensure the safety of life on navigable waters of the United States through the addition of regulations regarding port closures in the event of natural and other disasters and safety zones for firework barges.
The Coast proposes to make the following regulatory changes: (1) The disestablishment of the existing Safety/Security Zone: St. Johns River, Jacksonville, FL located in 33 CFR 165.720, (2) the creation of a new Safety Zone; Natural and Other Disasters in Ports of Jacksonville, Fernandina, and Canaveral, Florida to be located in 33 CFR 165.720, (3) and the addition of a new safety zone entitled “Safety Zone: St. Johns River, Jacksonville, FL” to be located in 33 CFR 165.723.
The existing Safety/Security Zone: St. Johns River, Jacksonville, FL (33 CFR 165.721) establishes safety and security zones around the waters of Blount Island, Jacksonville, FL under specified conditions. The fundamental reason for this safety/security zone still exists, however the regulation is redundant in nature. Under the authority of the Army Corps of Engineers, restricted areas were subsequently established in 2008. For further details, see Blount Island Command and Marine Corps Support Facility—Blount Island; Jacksonville, Florida restricted areas (33 CFR 334.515).
The proposed new safety zone, entitled “Safety Zone; Natural and Other Disasters in Ports of Jacksonville, Fernandina, and Canaveral, Florida” (33 CFR 165.720) would be added to provide the legal jurisdiction to close ports affected by natural and other disasters. In the past, temporary regulations regarding port closures have been published after natural and other disasters; however, publishing this notice in a permanent regulation provides better advance notice to the public regarding when port closures should be expected to occur, and would only require publication of a Notice of Enforcement during the storm itself, increasing efficiency and reducing the workload to the Coast Guard. There will be no change in the manner in which the public is notified by the Coast Guard of a port closure.
The proposed new safety zone, entitled “Safety Zone: St. Johns River, Jacksonville, FL” (33 CFR 165.723) would establish a safety zone around fireworks barges only between the Hart and Acosta Bridges. An additional regulation to encompass the Jacksonville Captain of the Port Zone will allow for a safety zone to be established around certain vessels and firework barges that pose a higher risk of injury to people or property without necessitating publication of a Temporary Final Rule for each individual event, which are often done with minimal notice to the public.
We developed this proposed rule after considering numerous statutes and executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes or executive orders.
This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866, Regulatory Planning and Review, as supplemented by Executive Order 13563, Improving Regulation and Regulatory Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of Executive Order 12866 or under section 1 of Executive Order 13563. The Office of Management and Budget has not reviewed it under those Orders.
This regulation is not significant regulatory action because most of the proposed regulations already exist in some form; such as natural and other disasters safety zones as a temporary final rule for each individual natural or other disasters and special local regulations for firework displays. The regulations that are being added are not expected to have a significant regulatory action due to the infrequency of use for the safety zones around firework barges. The removal of the safety and security zone for Blount Island would have no effect as the Restricted Area set in place by the Army Corps of Engineers will remain in effect.
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 proposed rule will not have a significant economic impact on a substantial number of small entities.
For the reasons discussed in the Regulatory Planning and Review section above, the proposed rule will not have a significant economic impact on a substantial number of small entities.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
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 proposed 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
This proposed 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 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. We have analyzed this proposed rule under that Order and determined that this rule 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 proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not cause a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed 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 proposed rule under Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination With Indian Tribal Governments, because it would 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 proposed rule is not a “significant energy action” under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed 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 made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves disestablishing of a safety and security zone, addition of port closures that would be otherwise published as a Temporary Final Rule, and addition of a safety zone to include all firework barge displays within the Jacksonville Captain of the Port Zone. This rule is categorically excluded from further review under paragraph 34(g) of Figure 2-1 of the Commandant Instruction. A preliminary environmental analysis checklist supporting this determination 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 proposes to amend 33 CFR part 165 as follows:
33 U.S.C. 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, 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
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(4) Persons and vessels desiring to enter, transit through, anchor in, or remain in the regulated area may contact the Captain of the Port Jacksonville via telephone at (904) 564-7513, or a designated representative via VHF radio on channel 16, to request authorization. If authorization to enter, transit through, anchor in, or remain in the regulated area is granted by the Captain of the Port Jacksonville or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port Jacksonville or a designated representative.
(5) Coast Guard Sector Jacksonville will attempt to notify the maritime community of periods during which these safety zones will be in effect via Broadcast Notice to Mariners or by on-scene designated representatives.
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(1) All persons and vessels are prohibited from entering, transiting through, anchoring in, or remaining within the regulated area unless authorized by the Coast Guard Captain of the Port Jacksonville or a designated representative.
(2) Persons and vessels desiring to enter, transit through, anchor in, or remain in the regulated area may contact the Captain of the Port Jacksonville via telephone at (904)-564-7513, or a designated representative via VHF radio on channel 16, to request authorization. If authorization to enter, transit through, anchor in, or remain in the regulated area is granted by the Captain of the Port Jacksonville or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port Jacksonville or a designated representative.
(3) The Coast Guard will provide notice of the regulated area via Broadcast Notice to Mariners or by on-scene designated representatives.
(4) This regulation does not apply to authorized law enforcement agencies operating within the regulated area.
Forest Service, USDA.
Notice of proposed rule; request for public comment.
Consistent with a court order on March 29, 2013, the U.S. Forest Service (Forest Service) is proposing to amend the agency's travel management rule (TMR) to require designation of National Forest System (NFS) roads, NFS trails, and areas on NFS lands where over-snow vehicle (OSV) use is allowed, restricted, or prohibited. Under the amended subpart C, the responsible official could establish a system of routes and areas where OSV use is prohibited except where allowed or a system of routes and areas where OSV use is allowed unless prohibited. The proposed rule would continue to exempt OSV use from subpart B of the TMR, which provides for designation of a system of routes and areas where motor vehicle use is allowed and prohibits motor vehicle use off the designated system.
Comments must be received in writing by August 4, 2014.
Submit comments electronically by following the instructions at the Federal eRulemaking portal at
Joseph Adamson, (202) 205-0931, Recreation, Heritage, and Volunteer Resources Staff.
Between 1982 and 2009, the number of people who operated motor vehicles off road increased by more than 153 percent in the United States (“Outdoor Recreation Trends and Futures, a Technical Document Supporting the Forest Service 2010 RPA [Resources Planning Act] Assessment,” p. 135 (H. Cordell, 2012)). While both motor vehicle use and OSV
In 2005, the Forest Service promulgated the TMR to provide more effective management of public motor vehicle use. Subpart B of the TMR requires designation of those NFS roads, NFS trails, and areas on NFS lands where public motor vehicle use is allowed (36 CFR 212.51(a)). Unless exempted from the designations, public motor vehicle use is prohibited off designated routes and outside designated areas (36 CFR 261.13). Under subpart B, the responsible official must establish a system of routes and areas where motor vehicle use is allowed. This information will be displayed for the public at local district offices. Motor vehicle use off the designated system is prohibited, unless it is exempted from the designations. Subpart C of the current TMR authorizes but does not require the responsible official to allow, restrict, or prohibit OSV use on NFS roads, NFS trails, and areas on NFS lands. Under subpart C, the responsible official has the discretion to determine whether to regulate OSV use and to establish a system of routes and areas where OSV use is allowed unless prohibited or a system of routes and areas where OSV use is prohibited unless allowed. The TMR treats OSVs differently from other types of motor vehicles because an OSV traveling over snow results in different impacts on natural and cultural resource values than motor vehicles traveling over the ground. Consequently, in contrast to motor vehicles, it may be appropriate for OSVs to travel off route. 69 FR 42386, 42389 (July 15, 2004) (proposed TMR); 70 FR 68273 (Nov. 9, 2005) (final TMR).
On March 29, 2013, the United States District Court for the District of Idaho ruled that subpart C of the TMR violated Executive Order (EO) 11644, as amended by EO 11989, governing use of off-road vehicles on federal lands in giving the Forest Service discretion to determine whether to regulate OSV use, and that the agency therefore improperly denied the plaintiff's petition to amend the TMR.
The Forest Service is proposing to amend subpart C of the TMR to provide for management of OSVs on NFS lands consistent with the EOs and the court's order. Specifically, the Forest Service is proposing to amend subpart C of the TMR to require the responsible official to designate NFS roads, NFS trails, and areas on NFS lands where OSV use is allowed, restricted, or prohibited in administrative units or Ranger Districts, or parts of administrative units or Ranger Districts, where snowfall is adequate for OSV use to occur. The Forest Service is not proposing to remove the exemption for OSVs from subpart B because the Agency wants to preserve the discretion in subpart C to establish a system of routes and areas where OSV use is allowed unless prohibited or a system of routes and areas where OSV use is prohibited unless allowed. In contrast, subpart B
The difference in management of motor vehicle use and OSV use on NFS lands stems from differences in their associated settings, activities, environmental impacts, and public preferences. National forests and grasslands change when snow blankets the landscape. Vegetation camouflages, animals burrow, and water transforms into ice. Recreationists and others accessing snow-covered National Forests and Grasslands typically trade hiking boots for skis and snowshoes and motor vehicles with tires for those with tracks and sleds.
Because of snowfall patterns, National Forests and Grasslands vary significantly in their need to address OSV use. National Visitor Use Monitoring (NVUM) data from 2008 to 2012 show that approximately 30 percent of NFS lands do not offer OSV recreation opportunities.
OSV use occurs only in the months when snow is present, in contrast to other types of motor vehicle use, which can occur at any time of the year. Other types of motor vehicles operating over snow are regulated under subpart B of the TMR.
A key difference between OSV use and other types of motor vehicle use is that, when properly operated and managed, OSVs do not make direct contact with soil, water, and vegetation, whereas most other types of motor vehicles operate directly on the ground. Unlike other types of motor vehicles traveling cross-country, OSVs traveling cross-country generally do not create a permanent trail or have a direct impact on soil and ground vegetation. In some areas of the country, OSV use is therefore not always confined to roads and trails.
The public's OSV preferences and practices on NFS lands vary nation-wide due to different terrain, snow typology and amount, recreational activities, and transportation needs. OSV use on NFS lands in the northeast and mid-west is largely trail-based, while the larger, wide-open, powder-filled bowls in western mountains support cross-country OSV use.
Subpart B of the TMR recognizes that cross-country travel by other types of motor vehicles is generally unacceptable. Subpart C of the TMR as originally promulgated and in the proposed rule recognizes that cross-country travel by OSVs may be acceptable in appropriate circumstances.
Recreational preferences are another factor accounting for the difference in management of other types of motor vehicle use and OSV use. The public's desire for recreational opportunities is different in the summer and the winter. NVUM data from 2008 to 2012 show that most public use of NFS lands (79 percent) occurs during non-snow seasons. Per NVUM data from 2008 to 2012, most snow season use on NFS lands (69 percent) occurs at alpine ski areas and generally does not involve OSVs, back-country skiing, snowshoeing, or any other snow-based activity.
Consistent with § 212.50(b) of subpart B of the current TMR, existing decisions that allow, restrict, or prohibit OSV use on NFS roads, NFS trails, or areas on NFS lands that were made under prior authorities (part 295 or subpart C) would remain in effect under the proposed rule and would not have to be revisited.
Analogous to § 212.52(a) of subpart B of the current TMR, the proposed rule would provide that public notice with no further public involvement would be sufficient if an administrative unit or a Ranger District has made previous administrative decisions, under other authorities and including public involvement, that allow, restrict, or prohibit OSV use on NFS roads, on NFS trails, and in areas on NFS lands over the entire administrative unit or Ranger District, or parts of the administrative unit or Ranger District, where snowfall is adequate for OSV use to occur and no change is proposed to these previous decisions. In short, existing OSV use determinations will remain in effect.
In requiring designation of NFS routes and areas on NFS lands where OSV use is allowed, restricted, or prohibited, the proposed rule would be consistent with the EOs and the court's order. Equally important, the resulting system of OSV routes and areas would sustain natural resource values, enhance user's experiences and provide opportunities for use on NFS lands.
Current § 212.1 of the TMR defines an area as a discrete, specifically delineated space that is smaller, and in most cases much smaller, than a Ranger District. The definition for an area in the proposed rule would recognize that cross-country OSV use may occur across a broader landscape. As with evaluation of an area for other types of motor vehicle use using the designation criteria in § 212.55, evaluation of an area for OSV use using the designation criteria in § 212.55 may be holistic and need not address each route within the area, as OSVs will be able to travel cross-country within it.
Current § 212.1 also defines “designated road, trail, or area”. To avoid conflict with this terminology in subpart B, the proposed rule would add a definition for “designation of over-snow vehicle use.”
The title of part 212, subpart C, would be changed from “Use by Over-Snow Vehicles” to “Over-Snow Vehicle Use.”
Current § 212.80 states that the purpose of subpart C is to provide for regulation of OSV use on NFS roads, NFS trails, and areas on NFS lands. The proposed rule would amend this section to require designation of NFS roads, NFS trails, and areas on NFS lands where OSV use is allowed, restricted, or prohibited. Consistent with § 212.50(b) in subpart B of the current TMR, the proposed rule would include a provision authorizing the responsible official to incorporate previous administrative decisions regarding OSV use made under other authorities in allowing, restricting, or prohibiting OSV use on NFS roads, on NFS trails, and in areas on NFS lands.
The proposed rule would amend § 212.81 to require designation of NFS roads, NFS trails, and areas on NFS lands where OSV use is allowed, restricted, or prohibited on administrative units or Ranger Districts, or parts of administrative units or Ranger Districts, of the NFS where snowfall is adequate for that use to occur, subject to the exemptions currently enumerated in § 212.81(b).
In contrast to subpart B and its corresponding prohibition at 36 CFR 261.13, which requires designation of a system of routes and areas that are open to motor vehicle use and prohibits motor vehicle use off the designated system, proposed subpart C would continue to allow the responsible official to designate a system of routes and areas where OSV use is allowed unless prohibited or a system of routes and areas where OSV use is prohibited unless allowed. An OSV use map could look like a motor vehicle use map, i.e., a map that identifies only the routes and areas where OSV use is allowed, or the opposite, i.e., a map that identifies only the routes and areas where OSV use is prohibited. In addition, local Forest Service officials would retain the discretion to manage OSV use to address local conditions and to establish restrictions, as appropriate, based on the season of use and other local factors. Decisions to designate OSV use may be made concurrently or separately from decisions to designate other types of motor vehicle use.
Consistent with § 212.52(a) of subpart B of the current TMR, § 212.81(b) of the proposed rule would provide that public notice with no further public involvement is sufficient if an administrative unit or Ranger District has made previous administrative decisions, under other authorities and including public involvement, that allow, restrict, or prohibit OSV use on NFS roads, on NFS trails, and in areas on NFS lands over the entire administrative unit or Ranger District, or parts of the administrative unit or Ranger District, where snowfall is adequate for OSV use to occur and no change is proposed to these previous decisions.
Except as modified by proposed § 212.81(b) governing prior comprehensive OSV decisions and proposed § 212.81(c) with respect to reference to the map displaying routes and areas where OSV use is allowed, restricted, or prohibited, § 212.81(c) of the proposed rule would apply the requirements governing designation of NFS roads, NFS trails, and areas on NFS lands in §§ 212.52 (public involvement); 212.53 (coordination with other governmental entities); 212.54 (revision of designations); 212.55 (criteria for designation of roads, trails, and areas); 212.56 (identification of designated roads, trails, and areas); and 212.57 (monitoring of effects of motor vehicle use) to designation of NFS roads, NFS trails, and areas on NFS lands where OSV use is allowed, restricted, or prohibited.
The title of § 261.14 would be changed from “Use by over-snow vehicles” to “Over-snow vehicle use.”
This proposed rule has been reviewed under USDA procedures and EO 12866 on regulatory planning and review. The Office of Management and Budget (OMB) has determined that this proposed rule is significant and is therefore subject to OMB review under E.O. 12866.
This proposed rule would require designation at the field level, with public input, of NFS roads, NFS trails, and areas on NFS lands where OSV use is allowed, restricted, or prohibited. This proposed rule would have no effect on the ground until designation of NFS roads, NFS trails, and areas on NFS lands for OSV use is completed at the field level, with opportunity for public involvement. Forest Service regulations at 36 CFR 220.6(d)(2) exclude from documentation in an environmental assessment or environmental impact statement “rules, regulations, or policies to establish service-wide administrative procedures, program processes, or instructions.” The Agency has concluded that this proposed rule falls within this category of actions and that no extraordinary circumstances exist which would require preparation of an environmental assessment or environmental impact statement.
This proposed rule has been considered in light of the Regulatory Flexibility Act (5 U.S.C. 602
The Agency has considered this proposed rule under the requirements of EO 13132 on federalism and has concluded that the proposed rule conforms with the federalism principles set out in this EO; would not impose any compliance costs on the States; and would not have substantial direct effects on the States, the relationship between the Federal Government and the States, or the distribution of power and responsibilities among the various levels of government. Therefore, the Agency has determined that no further assessment of federalism implications is necessary at this time. Moreover, this proposed rule does not have tribal implications as defined by EO 13175, entitled “Consultation and Coordination with Indian Tribal Governments,” and therefore advance consultation with Tribes is not required.
This proposed rule has been analyzed in accordance with the principles and criteria contained in EO 12630. The Agency has determined that the proposed rule would not pose the risk of a taking of private property.
This proposed rule does not contain any new recordkeeping or reporting requirements or other information collection requirements as defined in 5 U.S.C. 1320 that are not already required by law or not already approved for use. Accordingly, the review provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
This proposed rule has been reviewed under EO 13211, titled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.” The Agency has determined that this proposed rule does not constitute a significant energy action as defined in the EO.
This proposed rule has been reviewed under EO 12988 on civil justice reform. If the proposed rule were to be adopted, (1) all State and local laws and regulations that conflict with the proposed rule or that would impede its
Pursuant to Title II of the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538), which the President signed into law on March 22, 1995, the Agency has assessed the effects of this proposed rule on State, local, and Tribal governments and the private sector. This proposed rule would not compel the expenditure of $100 million or more by any State, local, or Tribal government or anyone in the private sector. Therefore, a statement under section 202 of the act is not required.
Highways and roads, National forests, Public lands—rights-of-way, Transportation.
Law enforcement, National forests.
Therefore, for the reasons set out in the preamble, the Forest Service proposes to amend 36 CFR parts 212 and 261 as follows:
16 U.S.C. 551, 23 U.S.C. 205.
7 U.S.C. 1011(f), 16 U.S.C. 551, E.O. 11644, 11989 (42 FR 26959).
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(1) Limited administrative use by the Forest Service;
(2) Use of any fire, military, emergency, or law enforcement vehicle for emergency purposes;
(3) Authorized use of any combat or combat support vehicle for national defense purposes;
(4) Law enforcement response to violations of law, including pursuit; and
(5) Over-snow vehicle use that is specifically authorized under a written authorization issued under Federal law or regulations.
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7 U.S.C. 1011(f); 16 U.S.C. 472, 551, 620(f), 1133(c), (d)(1), 1246(i).
United States Patent and Trademark Office, Commerce.
Notice of proposed rulemaking.
The United States Patent and Trademark Office (Office) is proposing changes to the rules of practice pertaining to the patent term adjustment provisions in view of the decision by the U.S. Court of Appeals for the Federal Circuit (Federal Circuit) in
Comments should be sent by electronic mail message over the Internet addressed to:
Comments further may be sent by electronic mail message over the Internet via the Federal eRulemaking Portal. See the Federal eRulemaking Portal Web site (
Although comments may be submitted by postal mail, the Office prefers to receive comments by electronic mail message over the Internet because sharing comments with the public is more easily accomplished. Electronic comments submitted in plain text are preferred, but may be submitted in ADOBE® portable document format or MICROSOFT WORD® format. Comments not submitted electronically should be submitted on paper in a format that facilitates convenient digital scanning into ADOBE® portable document format.
Comments will be available for viewing via the Office's Internet Web site (
Kery Fries, Senior Legal Advisor, Office of Patent Legal Administration, Office of the Deputy Commissioner for Patent Examination Policy, at telephone number 571-272-7757.
The Office makes the patent term adjustment determination indicated in the patent by a computer program that uses the information recorded in the Office's Patent Application Locating and Monitoring (PALM) system (except when an applicant requests reconsideration pursuant to § 1.705).
The patent term adjustment statutory provision also includes the provision that “[t]he period of adjustment of the term of a patent under [35 U.S.C. 154(b)(1)] shall be reduced by a period equal to the period of time during which the applicant failed to engage in reasonable efforts to conclude prosecution of the application,” and that “[t]he Director shall prescribe regulations establishing the circumstances that constitute a failure of an applicant to engage in reasonable efforts to conclude processing or examination of an application.”
The following is a discussion of proposed amendments to title 37 of the Code of Federal Regulations, Part 1:
Accordingly, prior notice and opportunity for public comment are not required pursuant to 5 U.S.C. 553(b) or (c) (or any other law), with respect to the proposed change to 37 CFR 1.703.
The proposed changes to the patent term adjustment reduction provisions do not impose any additional requirements or fees on applicants. The proposed change to 37 CFR 1.703 simply implements the Federal Circuit's ruling on the provisions of 35 U.S.C. 154(b)(1)(B)(i) in
For the foregoing reasons, the changes proposed in this notice will not have a significant economic impact on a substantial number of small entities.
This rulemaking does not add any additional requirements (including information collection requirements) or
Notwithstanding any other provision of 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 Paperwork Reduction Act unless that collection of information displays a currently valid OMB control number.
Administrative practice and procedure, Courts, Freedom of information, Inventions and patents, Reporting and recordkeeping requirements, Small businesses.
For the reasons set forth in the preamble, 37 CFR part 1 is proposed to be amended as follows:
35 U.S.C. 2(b)(2), unless otherwise noted.
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(1) The number of days, if any, in the period beginning on the date on which a request for continued examination of the application under 35 U.S.C. 132(b) was filed and ending on the date of mailing of a notice of allowance under 35 U.S.C. 151, unless prosecution in the application is reopened, in which case the period of adjustment under § 1.702(b) also does not include the number of days, if any, in the period or periods beginning on the date on which a request for continued examination of the application under 35 U.S.C. 132(b) was filed or the date of mailing of an action under 35 U.S.C. 132, whichever occurs first, and ending on the date of mailing of a subsequent notice of allowance under 35 U.S.C. 151;
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(12) Submission of a request for continued examination under 35 U.S.C. 132(b) after a notice of allowance under 35 U.S.C. 151 has been mailed, in which case the period of adjustment set forth in § 1.703 shall be reduced by the number of days, if any, beginning on the date of mailing of the notice of allowance under 35 U.S.C. 151 and ending on the date the request for continued examination under 35 U.S.C. 132(b) was filed;
Fish and Wildlife Service, Interior.
Proposed rule; reopening of comment period.
We, the U.S. Fish and Wildlife Service (Service), announce the reopening of the public comment period on the August 29, 2013, proposed designation of critical habitat for the Oregon spotted frog (
The comment period for the proposed rule published August 29, 2013 (at 78 FR 53538), is reopened. We will consider comments on that proposed rule or the changes to it proposed in this document that we receive or that are postmarked on or before July 18, 2014. Comments submitted electronically using the Federal eRulemaking Portal (see
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We request that you send comments only by the methods described above. We will post all comments on
Ken S. Berg, Manager, U.S. Fish and Wildlife Service, Washington Fish and Wildlife Office, 510 Desmond Drive SE., Suite 102, Lacey, WA 98503; telephone 360-753-9440; or facsimile 360-753-9445. Persons who use a telecommunications device for the deaf (TDD) may call the
We will accept written comments and information during this reopened comment period on our proposed designation of critical habitat for the Oregon spotted frog that was published in the
(1) The reasons why we should or should not designate habitat as “critical habitat” under section 4 of the Act (16 U.S.C. 1531 et seq.), including whether there are threats to the species from human activity, the degree of which can be expected to increase due to the designation, and whether that increase in threats outweighs the benefit of designation such that the designation of critical habitat is not prudent.
(2) Specific information on:
(a) The amount and distribution of Oregon spotted frog habitat;
(b) What may constitute “physical or biological features essential to the conservation of the species,” within the geographical range currently occupied by the Oregon spotted frog;
(c) Where these features are currently found;
(d) Whether any of these features may require special management considerations or protection;
(e) What areas, that were occupied at the time of listing (or are currently occupied) and that contain features essential to the conservation of the species, should be included in the designation and why;
(f) What areas not occupied at the time of listing are essential for the conservation of the species and why;
(g) Whether there are any specific areas where the proposed critical habitat boundaries should be expanded to include adjacent riparian areas, what factors or features should be considered in determining an appropriate boundary revision, and why this would be biologically necessary or unnecessary; and
(h) Additional research studies or information regarding the movement distances or patterns of Oregon spotted frogs.
(3) Land use designations and current or planned activities in the areas proposed to be designated as critical habitat, and possible impacts of these activities on the proposed critical habitat.
(4) Information on the projected and reasonably likely impacts of climate change on the Oregon spotted frog within the proposed critical habitat areas.
(5) Any probable economic, national security, or other relevant impacts of designating any area that may be included in the final designation; in particular, we seek information on any impacts on small entities or families, and the benefits of including or excluding areas from the proposed designation that exhibit these impacts.
(6) Whether our approach to designating critical habitat could be improved or modified in any way to provide for greater public participation and understanding, or to assist us in accommodating public concerns and comments.
(7) Information on the extent to which the description of economic impacts in the draft economic analysis is a reasonable estimate of the likely economic impacts.
(8) The likelihood of adverse social reactions to the designation of critical habitat, as discussed in the associated documents of the draft economic analysis, and how the consequences of such reactions, if likely to occur, would relate to the conservation and regulatory benefits of the proposed critical habitat designation.
If you submitted comments or information on the proposed rule (78 FR 53538) during the initial comment period from August 29, 2013, to November 12, 2013, please do not resubmit them. We will incorporate them into the public record as part of this comment period, and we will fully consider them in the preparation of our final determination. Our final determination concerning critical habitat will take into consideration all written comments and any additional information we receive during both comment periods. On the basis of public comments, we may, during the development of our final determination, find that areas proposed are not essential, are appropriate for exclusion under section 4(b)(2) of the Act, or are not appropriate for exclusion.
You may submit your comments and materials concerning the proposed rule or DEA by one of the methods listed in the
If you submit a comment via
Comments and materials we receive, as well as supporting documentation we used in preparing the proposed rule and DEA, will be available for public inspection on
It is our intent to discuss only those topics directly relevant to the designation of critical habitat for Oregon spotted frog in this document. For more information on previous Federal actions concerning the Oregon spotted frog, refer to the proposed designation of critical habitat published in the
On August 29, 2013, we published a proposed rule to list the Oregon spotted frog as a threatened species (78 FR 53582) and a proposed rule to designate critical habitat for the Oregon spotted frog (78 FR 53538). We proposed to designate approximately 68,192 acres (27,597 hectares (ha)) and approximately 24 river miles (mi) (38 river kilometers (km)) in 14 units located in Washington and Oregon as critical habitat. That proposal had a 60-day comment period, to end October 28, 2013. On September 26, 2013, we extended the public comment period an additional 15 days, until November 12, 2013, to allow all interested parties additional time to comment on the
Section 3 of the Act defines critical habitat as the specific areas within the geographical area occupied by a species, at the time it is listed in accordance with the Act, on which are found those physical or biological features essential to the conservation of the species and that may require special management considerations or protection, and specific areas outside the geographical area occupied by a species at the time it is listed, upon a determination that such areas are essential for the conservation of the species. If the proposed rule is made final, section 7 of the Act will prohibit destruction or adverse modification of critical habitat by any activity funded, authorized, or carried out by any Federal agency. Federal agencies proposing actions affecting critical habitat must consult with us on the effects of their proposed actions under section 7(a)(2) of the Act.
The Service received new information from Federal partners and the public that led to our refinement of four of the proposed critical habitat units in Oregon. We are proposing to expand the four units to include a total of 309 additional acres (125 additional ha). All of the additional areas are known to be occupied by Oregon spotted frogs and are subject to the same suite of activities described in our August 29, 2013, proposed designation (78 FR 53538). The approximate acreages to be added to the four units, as well as the landownership, are shown below in Table 1. There are no changes being proposed in the other 10 proposed critical habitat units.
A comment we received from a peer reviewer indicated that the proposed critical habitat unit did not include overwintering habitat currently used by Oregon spotted frogs at Camas Prairie (Corkran 2013). Upon consideration of the information we received, we propose to include an additional 27 acres (11 ha) of the meadow and springs that provide overwintering habitat for the Oregon spotted frog. The additional acreage is occupied by the Oregon spotted frog, contains the physical or biological features essential to the conservation of the species, and occurs entirely on the Mt. Hood National Forest. The essential features within the additional acres may require special management considerations or protection to ensure maintenance or improvement of existing overwintering habitat, aquatic movement corridors, or refugia habitat, and to address any changes that could affect these features. The total acreage of proposed critical habitat in Unit 7, after this refinement, is 96 acres (39 ha) in Wasco County, Oregon.
New information we received from the U.S. Geological Survey indicated that the proposed critical habitat unit did not include the full extent of occupancy by Oregon spotted frogs along Jack Creek (C. Pearl, USGS, pers. comm. 2014). Therefore, we propose to include an additional 180 acres (73 ha) in this unit. Upon consideration of the information we received, this refinement includes approximately 3.1 miles (5 km) of Jack Creek and its adjacent seasonally wetted areas south of U.S. Forest Service Road 88 through 1.32 mi (2.12 km) of O'Connor Meadow. The additional acreage is occupied by the Oregon spotted frog and contains the physical or biological features essential to the conservation of the species. Eighty-two acres (33 ha) are managed by the Fremont-Winema National Forest, and 98 acres (40 ha) are privately owned. The essential features within the additional acres may require special management considerations or protection to ensure maintenance or improvement of the existing nonbreeding, breeding, rearing, and overwintering habitat; aquatic movement corridors; or refugia habitat, and to address any changes that could affect these features. The total acreage of proposed critical habitat in Unit 12, after this refinement, is 15,332 acres (6,205 ha) in Klamath County, Oregon.
New information we received from the U.S. Geological Survey and National Park Service indicated that the proposed critical habitat unit did not include the full extent of occupancy by Oregon spotted frogs (D. Hering, NPS, pers. comm. 2014; C. Pearl, pers. comm. 2013). Upon consideration of the information we received, we propose to include an additional 85 acres (34 ha) in this unit. This refinement includes approximately 0.75 mi (1.2 km) of Annie Creek and the associated, adjacent, seasonally wetted areas from the Annie Creek Sno-Park downstream to its junction with the Wood River;
New information we received from the U.S. Forest Service indicated the proposed critical habitat unit did not include the full extent of occupancy by Oregon spotted frogs (T. Smith, USFS, pers. comm. 2014). Therefore, we propose to include an additional 17 acres (7 ha) in this unit. Upon consideration of the information we received, this refinement includes an additional portion of the Buck Lake drainage system of canals, as well as Spencer Creek from Buck Lake downstream approximately 1.6 miles (2.6 km), ending at the intersection of U.S. Forest Service Road 46 and Clover Creek Road. The additional acreage is occupied by the Oregon spotted frog and contains the essential physical or biological features. Fifteen acres (6 ha) are managed by the Bureau of Land Management and Fremont-Winema National Forest, and 2 acres (1 ha) are privately owned. The essential features within the additional acres may require special management considerations or protection to ensure maintenance or improvement of the existing nonbreeding, breeding, rearing, and overwintering habitat; aquatic movement corridors; or refugia habitat, and to address any changes that could affect these features. The total acreage of proposed critical habitat in Unit 14, after this refinement, is 262 acres (106 ha) in Klamath and Jackson Counties, Oregon.
Section 4(b)(2) of the Act requires that we designate or revise critical habitat based upon the best scientific data available, after taking into consideration the economic impact, impact on national security, or any other relevant impact of specifying any particular area as critical habitat. We may exclude an area from critical habitat if we determine that the benefits of excluding the area outweigh the benefits of including the area as critical habitat, provided such exclusion will not result in the extinction of the species.
When considering the benefits of inclusion for an area, we consider among other factors, the additional regulatory benefits that an area would receive through the analysis under section 7 of the Act addressing the destruction or adverse modification of critical habitat as a result of actions with a Federal nexus (activities conducted, funded, permitted, or authorized by Federal agencies), the educational benefits of identifying areas containing essential features that aid in the recovery of the listed species, and any ancillary benefits triggered by existing local, State or Federal laws as a result of the critical habitat designation.
When considering the benefits of exclusion, we consider, among other things, whether exclusion of a specific area is likely to incentivize or result in conservation; the continuation, strengthening, or encouragement of partnerships; or implementation of a management plan. In the case of the Oregon spotted frog, the benefits of critical habitat include public awareness of the presence of the Oregon spotted frog and the importance of habitat protection, and, where a Federal nexus exists, increased habitat protection for the Oregon spotted frog due to protection from adverse modification or destruction of critical habitat. In practice, situations with a Federal nexus exist primarily on Federal lands or for projects undertaken by Federal agencies.
The final decision on whether to exclude any areas will be based on the best scientific data available at the time of the final designation, including information obtained during the comment period and information about the economic impact of designation. Accordingly, we have prepared a draft economic analysis concerning the proposed critical habitat designation (DEA), which is available for review and comment (see
Section 4(b)(2) of the Act and its implementing regulations require that we consider the economic impact that may result from a designation of critical habitat. To assess the probable economic impacts of a designation, we must first evaluate specific land uses or activities and projects that may occur in the area of the critical habitat. We then must evaluate the impacts that a specific critical habitat designation may have on restricting or modifying specific land uses or activities for the benefit of the species and its habitat within the areas proposed. We then identify which conservation efforts may be the result of the species being listed under the Act versus those attributed solely to the designation of critical habitat for this particular species. The probable economic impact of a proposed critical habitat designation is analyzed by comparing scenarios “with critical habitat” and “without critical habitat.” The “without critical habitat” scenario represents the baseline for the analysis, which includes the existing regulatory and socio-economic burden imposed on landowners, managers, or other resource users potentially affected by the designation of critical habitat (e.g., under the Federal listing as well as other Federal, State, and local regulations). The baseline, therefore, represents the costs of all efforts attributable to the listing of the species under the Act (i.e., conservation of the species and its habitat incurred regardless of whether critical habitat is designated). The “with critical habitat” scenario describes the incremental impacts associated specifically with the designation of critical habitat for the species. The incremental conservation efforts and associated impacts would not be expected without the designation of critical habitat for the species. In other words, the incremental costs are those attributable solely to the designation of critical habitat, above and beyond the baseline costs. These are the costs we use when evaluating the benefits of inclusion and exclusion of particular areas from the final designation of critical habitat should we choose to conduct an optional section 4(b)(2) exclusion analysis.
For this particular designation, we developed an incremental effects memorandum (IEM) considering the probable incremental economic impacts that may result from this proposed designation of critical habitat. The information contained in our IEM was then used to develop a screening analysis of the probable effects of the designation of critical habitat for the
Executive Orders (E.O.) 12866 and 13563 direct Federal agencies to assess the costs and benefits of available regulatory alternatives in quantitative (to the extent feasible) and qualitative terms. Consistent with the E.O. regulatory analysis requirements, our effects analysis under the Act may take into consideration impacts to both directly and indirectly impacted entities, where practicable and reasonable. We assess, to the extent practicable, the probable impacts, if sufficient data are available, to both directly and indirectly impacted entities. As part of our screening analysis, we considered the types of economic activities that are likely to occur within the areas likely affected by the critical habitat designation. In our evaluation of the probable incremental economic impacts that may result from the proposed designation of critical habitat for the Oregon spotted frog, first we identified, in the IEM dated January 14, 2014, and the IEM addendum dated February 13, 2014, probable incremental economic impacts associated with the following categories of activities: (1) Grazing, (2) water management, (3) land restoration and conservation, (4) agriculture, (5) recreation, and (6) transportation activities. We considered each industry or category individually. Additionally, we considered whether their activities have any Federal involvement. Critical habitat designation will not affect activities that do not have any Federal involvement; designation of critical habitat only affects activities conducted, funded, permitted, or authorized by Federal agencies. If the listing proposal is made final, in areas where the Oregon spotted frog is present, Federal agencies would be required to consult with the Service under section 7 of the Act on activities they fund, permit, or implement that may affect the species. If we also finalize the proposed critical habitat designation, consultations to avoid the destruction or adverse modification of critical habitat would be incorporated into the existing consultation process. Therefore, disproportionate impacts to any geographic area or sector are not likely as a result of this critical habitat designation.
In our IEM, we attempted to clarify the distinction between the effects that would result from the species being listed and those attributable to the critical habitat designation (i.e., difference between the jeopardy and adverse modification standards) for the Oregon spotted frog's critical habitat. Because the designation of critical habitat for Oregon spotted frog was proposed concurrently with the listing, it has been our experience that it is more difficult to discern which conservation efforts are attributable to the species being listed and those which will result solely from the designation of critical habitat. However, the following specific circumstances in this case help to inform our evaluation: (1) The essential physical or biological features identified for critical habitat are the same features essential for the life history requisites of the species, and (2) any actions that would result in sufficient harm or harassment to constitute jeopardy to the Oregon spotted frog would also likely adversely affect the essential physical and biological features of critical habitat. The IEM outlines our rationale concerning this limited distinction between baseline conservation efforts and incremental impacts of the designation of critical habitat for this species. This evaluation of the incremental effects has been used as the basis to evaluate the probable incremental economic impacts of the proposed designation of critical habitat.
The proposed critical habitat designation for the Oregon spotted frog totals approximately 68,500 acres (27,721 ha) and 24 river mi (38 river km). The majority of these areas are occupied by the Oregon spotted frog, although approximately 365 acres (148 ha) and less than 1 river mile are not known to be occupied by the species. In occupied areas, any actions that may affect the species or its habitat would also affect designated critical habitat, and it is unlikely that any additional conservation efforts would be recommended to address the adverse modification standard over and above those recommended as necessary to avoid jeopardizing the continued existence of the Oregon spotted frog. Additionally, in areas proposed as critical habitat that are not known to be occupied by the Oregon spotted frog, Federal action agencies are likely to treat these areas as potentially occupied due to their proximity to occupied areas, and any project modifications requested to avoid adverse modification are likely to be the same as those needed to avoid jeopardy. Therefore, only administrative costs are expected due to the proposed critical habitat designation. While this additional analysis will require time and resources by both the Federal action agency and the Service, it is believed that, in most circumstances, these costs would predominantly be administrative in nature and would not be significant. The unit likely to incur the largest incremental administrative costs is Unit 9 (Little Deschutes River) due to a relatively high number of anticipated consultations to consider grazing allotments intersecting the unit. The total incremental administrative costs associated with all known future actions are estimated to be $190,000. Thus, future probable incremental economic impacts are not likely to exceed $100 million in any single year and disproportionate impacts to any geographic area or sector are not likely as a result of this critical habitat designation.
Therefore, the probable incremental economic impacts of the Oregon spotted frog critical habitat designation are expected to be limited to additional administrative effort in conducting future section 7 consultations. This is due to three factors: (1) In occupied areas, activities with a Federal nexus would be subject to section 7 consultation requirements regardless of critical habitat designation, due to the presence of the listed species; (2) In areas not known to be occupied, agencies would in most cases be likely
As we stated earlier, we are soliciting data and comments from the public on the DEA, as well as all aspects of the proposed rule and our amended required determinations. We may revise the proposed rule or supporting documents to incorporate or address information we receive during the public comment period. In particular, we may exclude an area from critical habitat if we determine that the benefits of excluding the area outweigh the benefits of including the area, provided the exclusion will not result in the extinction of this species.
In our August 29, 2013, proposed rule (78 FR 53538), we determined our compliance with several statutes and executive orders. Following our evaluation of the probable incremental economic impacts resulting from the designation of critical habitat for the Oregon spotted frog, we have amended or affirmed our determinations below. Specifically, we affirm the information in our proposed rule concerning Executive Orders (E.O.s) 12866 and 13563 (Regulatory Planning and Review), E.O. 13132 (Federalism), E.O. 12988 (Civil Justice Reform), E.O. 13211 (Energy, Supply, Distribution, or Use), the Unfunded Mandates Reform Act (2 U.S.C. 1501
Under the Regulatory Flexibility Act (RFA; 5 U.S.C. 601
According to the Small Business Administration, small entities include small organizations such as independent nonprofit organizations; small governmental jurisdictions, including school boards and city and town governments that serve fewer than 50,000 residents; and small businesses (13 CFR 121.201). Small businesses include manufacturing and mining concerns with fewer than 500 employees, wholesale trade entities with fewer than 100 employees, retail and service businesses with less than $5 million in annual sales, general and heavy construction businesses with less than $27.5 million in annual business, special trade contractors doing less than $11.5 million in annual business, and agricultural businesses with annual sales less than $750,000. To determine if potential economic impacts to these small entities are significant, we considered the types of activities that might trigger regulatory impacts under this designation as well as types of project modifications that may result. In general, the term “significant economic impact” is meant to apply to a typical small business firm's business operations.
The Service's current understanding of the requirements under the RFA, as amended, and following recent court decisions, is that Federal agencies are only required to evaluate the potential incremental impacts of rulemaking on those entities directly regulated by the rulemaking itself, and therefore, not required to evaluate the potential impacts to indirectly regulated entities. The regulatory mechanism through which critical habitat protections are realized is section 7 of the Act, which requires Federal agencies, in consultation with the Service, to ensure that any action authorized, funded, or carried out by the agency is not likely to adversely modify critical habitat. Therefore, under these circumstances only Federal action agencies are directly subject to the specific regulatory requirement (avoiding destruction and adverse modification) imposed by critical habitat designation. Under these circumstances, it is our position that only Federal action agencies will be directly regulated by this designation. Federal agencies are not small entities and to this end, there is no requirement under RFA to evaluate the potential impacts to entities not directly regulated. Therefore, because no small entities are directly regulated by this rulemaking, the Service certifies that, if promulgated, the proposed critical habitat designation will not have a significant economic impact on a substantial number of small entities.
In summary, we have considered whether the proposed designation would result in a significant economic impact on a substantial number of small entities. For the above reasons and based on currently available information, we certify that, if promulgated, the proposed critical habitat designation would not have a significant economic impact on a substantial number of small business entities. Therefore, an initial regulatory flexibility analysis is not required.
In accordance with E.O. 12630 (Government Actions and Interference with Constitutionally Protected Private Property Rights), we have analyzed the potential takings implications of designating critical habitat for the Oregon spotted frog in a takings implications assessment. As discussed above, the designation of critical habitat affects only Federal actions. Although private parties that receive Federal funding, assistance, or require approval or authorization from a Federal agency for an action may be indirectly impacted by the designation of critical habitat, the legally binding duty to avoid destruction or adverse modification of critical habitat rests squarely on the Federal agency. The economic analysis found that no significant economic impacts are likely to result from the designation of critical habitat for the Oregon spotted frog. Because the Act's critical habitat protection requirements apply only to Federal agency actions, few conflicts between critical habitat and private property rights should result from this designation. Based on information contained in the economic analysis assessment and described within this document, it is not likely that economic impacts to a property owner would be of a sufficient magnitude to support a takings action. Therefore, the takings implications assessment concludes that this designation of critical habitat for Oregon spotted frog does not pose significant takings implications for lands within or affected by the designation.
The primary authors of this notice are the staff members of the Washington Fish and Wildlife Office, Oregon Fish and Wildlife Office-Bend Field Office, and Klamath Falls Fish and Wildlife Office.
Endangered and threatened species, Exports, Imports, Reporting and recordkeeping requirements, Transportation.
Accordingly, we propose to further amend part 17, subchapter B of chapter I, title 50 of the Code of Federal Regulations, as proposed to be amended on August 29, 2013, at 78 FR 53538, as set forth below:
16 U.S.C. 1361-1407; 1531-1544; 4201-4245, unless otherwise noted.
(d)
Oregon Spotted Frog (
(12) Unit 7: Lower Deschutes River, Wasco County, Oregon. Map of Unit 7 follows:
(18) Unit 12: Williamson River, Klamath County, Oregon. Map of Unit 12 follows:
(19) Unit 13: Upper Klamath Lake, Klamath County, Oregon. Map of Unit 13 follows:
(20) Unit 14: Upper Klamath, Jackson and Klamath Counties, Oregon. Map of Unit 14 follows:
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Proposed rule; request for comments.
NMFS issues a proposed rule to implement Amendment 106 to the Fishery Management Plan for Groundfish of the Bering Sea and Aleutian Islands Management Area (BSAI FMP). The proposed rule would allow the owner of an American Fisheries Act (AFA) vessel to rebuild or replace the vessel without limitation on the length, weight, or horsepower of the rebuilt or replacement vessel when the vessel is operating in the Bering Sea and Aleutian Islands Management Area (BSAI). The proposed rule would also allow the owner of an AFA catcher vessel that is a member of an inshore cooperative to remove the vessel from the Bering Sea directed pollock fishery and assign the pollock catch history of the removed vessel to one or more vessels in the inshore cooperative to which the removed vessel belonged. This action is necessary to bring the regulations implementing the BSAI FMP into conformity with the AFA as amended by the Coast Guard Authorization Act of 2010. This action would also improve vessel safety and operational efficiency in the AFA fleet by allowing the rebuilding or replacement of AFA vessels with safer and more efficient vessels and by allowing the removal of inactive catcher vessels from the AFA fishery. This action is intended to promote the goals and objectives of the Magnuson-Stevens Fishery Conservation and Management Act, the AFA, the BSAI FMP, and other applicable laws.
Submit comments on or before August 4, 2014.
You may submit comments, identified by NOAA-NMFS-2013-0097, by any one of the following methods:
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Written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this proposed rule may be submitted to NMFS at the above address; emailed to
Electronic copies of Amendment 106 to the FMP, the Regulatory Impact Review/Initial Regulatory Flexibility Analysis (Analysis), and the Categorical Exclusion prepared for this action may be obtained from
Additional analyses prepared for the AFA include the Final Environmental Impact Statement (FEIS) for American Fisheries Act Amendments 61/61/13/8 (AFA FEIS) (February 2002); the FEIS for Essential Fish Habitat Identification and Conservation in Alaska (April 2005); the Alaska Groundfish Harvest Specifications—FEIS (January 2007); and the Bering Sea Chinook Salmon Bycatch Management—FEIS (December 2009). These analyses are available on the NMFS Alaska Region Web site at
Mary Alice McKeen, 907-586-7228.
NMFS manages the groundfish fisheries of the BSAI in the Exclusive Economic Zone off Alaska under the BSAI FMP. The North Pacific Fishery Management Council (Council) prepared, and the Secretary of Commerce (Secretary) approved, the BSAI FMP pursuant to the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act) and other applicable laws. General regulations that pertain to U.S. fisheries appear at subpart H of 50 CFR part 600. Regulations implementing the BSAI FMP appear at 50 CFR part 679. Unless noted otherwise, all references to regulations in this proposed rule are to regulations that are contained in Title 50 of the CFR.
This document uses several terms to help the reader understand the provisions of the proposed rule. The definitions are provided here for ease of reference.
The term “AFA vessel” means a vessel that is named on an AFA catcher vessel permit, an AFA catcher/processor permit, or an AFA mothership permit and is authorized by that permit to participate in the directed pollock fishery in the Bering Sea. The proposed rule would add this definition to § 679.2.
The terms “directed pollock fishery” or “AFA fishery” mean directed fishing for pollock in the Bering Sea subarea. “Directed fishing” is defined in regulations at § 679.2.
The term “original AFA” means the provisions of the AFA as adopted on October 21, 1998. The original AFA was contained in Division C, Title II—Fisheries, Subtitles I and II, within the Omnibus Appropriations Act FY 1999, Public Law 105-277.
The terms “amended AFA” or “AFA” mean the American Fisheries Act as amended since 1998, including the amendments to the AFA made by section 602 of the Coast Guard Authorization Act of 2010 (Coast Guard Act), Public Law. 111-281.
The term “original AFA vessel” means a vessel that became eligible to participate in the directed pollock fishery under the terms of the original AFA.
The Background portion of this proposed rule contains four sections. Section I describes the relevant statutes and regulations governing the AFA fishery prior to the Coast Guard Act. Section II describes the changes to the AFA made by the Coast Guard Act. Section III describes the history of Council action to address the changes made to the AFA by the Coast Guard Act. Section IV describes the need for this action.
On October 21, 1998, the President signed into law the original AFA. The original AFA, as adopted in 1998, is available on the NMFS Alaska Region Web site:
Subtitle I of the original AFA, entitled Fishery Endorsements, comprised sections 201 to 204. Subtitle I made changes generally in the issuance of Federal fishery endorsements by the United States Coast Guard (Coast Guard). These changes were initially codified at 46 U.S.C. 12102 and are now found at 46 U.S.C. 12113. Subtitle II of the original AFA, entitled Bering Sea Pollock Fishery, comprised sections 205 through 213. Subtitle II changed the management of the directed pollock fishery in the BSAI. Subtitle II of the original AFA is codified as a statutory note to section 301 of the Magnuson-Stevens Act (16 U.S.C.A. 1851 note). The following paragraphs briefly describe the provisions in Subtitle I and Subtitle II.
Before the original AFA, a vessel that was five net tons or greater had to have a Federal certificate of documentation with a Federal fishery endorsement to operate as a fishing vessel in U.S. waters (46 U.S.C. 12102(a) (1997); 46 U.S.C. 12108 (1997)). For a vessel to receive a Federal fishery endorsement, the owner of the vessel had to be a U.S. citizen or, if the owner of the vessel was a corporation, the controlling interest in the corporation had to be owned by individuals who were citizens of the United States (46 U.S.C. 12102(c) (1997)).
Subtitle I of the original AFA made two changes in the issuance of Federal fishery endorsements. First, it tightened the requirements for a non-individual entity, such as a corporation, to show that U.S. citizens held a controlling interest in the entity. Subtitle I of the original AFA established a standard of at least 75 percent ownership by U.S. citizens at each tier of ownership of the entity and in the aggregate. For vessels 100 feet or greater in registered length, Subtitle I of the original AFA tasked the Maritime Administration (MARAD), an agency in the Department of Transportation, with making the citizenship determinations for vessel ownership. For vessels less than 100 feet in registered length, the Coast Guard retained the responsibility to make the citizenship determinations for vessel ownership. Subtitle I of the original AFA corrected what Congress believed were mistakes in, and misinterpretations of, the 1987 Commercial Fishing Industry Anti-Reflagging Act. These mistakes and misinterpretations had resulted in the exemption of most vessels from the U.S. citizenship requirements (AFA FEIS at pages 1-3, see
Second, Subtitle I of the original AFA prohibited the issuance of Federal fishery endorsements to any new fishing vessels that exceeded 165 feet in registered length, that exceeded 750 gross registered tons, or that had an engine or engines capable of producing more than 3,000 shaft horsepower (46 U.S.C. 12113). MARAD regulations refer to vessels that exceed any of these statutory criteria of 165 feet registered length, 750 gross registered tons, or 3,000 shaft horsepower, as “large vessels” (46 CFR 356.47). If a vessel was a large vessel, the vessel could not receive a Federal fishery endorsement unless (1) the vessel had a certificate of documentation with a fishery endorsement that was effective on September 25, 1997; or (2) a regional fishery management council recommended and the Secretary of Commerce approved conservation and management measures in accordance with the Magnuson-Stevens Act to allow participation by large vessels in fisheries under the council's authority.
All original AFA vessels had fishery endorsements as of September 25, 1997. Therefore, all original AFA vessels were eligible to receive a Federal fishery endorsement even if the vessel was a “large vessel.”
Subtitle II of the original AFA made sweeping changes in the management of the directed pollock fishery in the BSAI and changed, to a lesser extent, the management of other groundfish fisheries off Alaska. In 2002, NMFS implemented the AFA through the following amendments to fishery management plans: Amendment 61 to the BSAI FMP; Amendment 61 to the Fishery Management Plan for Groundfish of the Gulf of Alaska (GOA FMP); Amendment 13 to the Fishery Management Plan for Bering Sea/Aleutian Islands King and Tanner Crabs; and Amendment 8 to the Fishery Management Plan for the Scallop Fishery off Alaska. NMFS analyzed the impact of the original AFA and the related fishery management plan amendments in the AFA FEIS (see
Subtitle II of the original AFA made five major changes in the management of pollock and other groundfish fisheries off Alaska: (1) Sector allocations, (2) determination of eligible vessels and processors, (3) the allowance of cooperatives; (4) protection measures for other fisheries, and (5) catch weighing and monitoring requirements. These changes are described in detail in the AFA FEIS and are summarized briefly here.
• Sector allocations. The original AFA in section 206 established sector allocations for the BSAI pollock fishery. The original AFA allocated 10 percent of the BSAI pollock total allowable catch (TAC) to the Western Alaska Community Development Quota (CDQ) Program. After allowance for incidental catch of pollock in other fisheries, the original AFA allocated the remaining TAC as follows: a 50 percent allocation to catcher vessels harvesting pollock for processing by the inshore sector; a 40 percent allocation to catcher vessels and catcher/processors harvesting pollock for processing by the catcher/processor sector; and a 10 percent allocation to catcher vessels harvesting pollock for processing by the mothership sector.
• Eligible vessels and processors. The original AFA in section 208 established which vessels and which processors were eligible to participate in the mothership sector, the catcher/processor sector, and the inshore sector. The mothership sector and the catcher/processor sector together make up the offshore component of the Bering Sea pollock fishery. A mothership may only receive and process fish; a catcher/processor may process and harvest fish; a catcher vessel may only harvest fish (section 205 of original AFA).
NMFS initially issued AFA permits to 3 mothership vessels, 21 catcher/processor vessels, and 112 catcher vessels. The three AFA mothership vessels were listed by name as eligible vessels in the AFA. Of the 21 AFA catcher/processors, 20 vessels were listed catcher/processors, which means they were listed by name as eligible in
• Cooperatives. The original AFA in section 210 allowed the formation of fishery cooperatives in each AFA sector. Under a fishery cooperative, the members of a cooperative agree to divide up the pollock that the cooperative members may harvest or process in a manner that seeks to eliminate “a wasteful race for fish” and to allow participants “to maximize productivity” (AFA FEIS, Executive Summary at page 2, see
Seven inshore cooperatives have formed (Analysis, Section 1.9.1). Almost all AFA inshore catcher vessels harvest and deliver pollock through a cooperative, rather than in open access. From 2005 to 2014, except for 2010, all inshore catcher vessels fished through a cooperative (Allocations, NMFS Alaska Region Web site,
• Limits on AFA vessels in other fisheries. The original AFA in section 211 provided protections for other fisheries from spillover effects from the allocation of exclusive harvesting privileges in the Bering Sea pollock fishery and the formation of fishery cooperatives. With respect to fisheries outside of Alaska, section 211(b)(5) of the original AFA prohibited AFA catcher/processors and AFA motherships from participating in any fishery outside of Alaska except the Pacific whiting fishery, unless a regional fishery management council specifically authorized such participation.
With regard to fishing in the Exclusive Economic Zone off Alaska, the original AFA provided for limits on AFA vessels that have become known as sideboards. Sideboards are limits on the amount of a species, other than Bering Sea pollock, that AFA vessels may harvest. The original AFA in section 211(b) established sideboard limits in the BSAI and GOA for the 20 catcher/processors that were listed in the original AFA as eligible to participate in the directed pollock fishery. The original AFA in section 211(a) directed the Council to recommend additional sideboard protections. The Council did recommend, and the Secretary approved, a comprehensive set of sideboard regulations on AFA vessels for species other than Bering Sea pollock (see regulations at § 679.64).
The regulations subject most AFA catcher vessels to sideboard limits (§ 679.4). NMFS establishes the sideboard limits, by species, each year through the annual harvest specification process. (See, e.g., Final 2013 and 2014 Harvest Specifications for Groundfish in the GOA, Tables 19 and 20, 78 FR 13162, February 26, 2013). If a sideboard limit for a species is too low to support a directed fishery, NMFS closes the fishery to directed fishing by AFA-sideboarded catcher vessels (§ 679.20(d)(iii) and (iv)). This frequently occurs. For example, in 2013 and 2014, except for pollock and Pacific cod in Western and Central GOA, NMFS closed directed fishing by AFA-sideboarded catcher vessels for almost all other groundfish species in the GOA (Final 2013 and 2014 Harvest Specifications for Groundfish in the GOA, Tables 30 and 31, 78 FR 13162, February 26, 2013).
The regulations exempt some AFA catcher vessels from sideboard limits for BSAI Pacific cod and for GOA groundfish, if the vessels meet specified criteria (§ 679.64(b)(2)). Out of 112 AFA catcher vessels, 10 vessels are exempt from BSAI Pacific cod sideboards and 16 vessels are exempt from GOA sideboards (Analysis, Section 1.9.1). These vessels are known as “sideboard-exempt” vessels. Even though exempt from AFA sideboards, the AFA sideboard-exempt vessels are bound by TACs for BSAI Pacific cod and GOA groundfish species and are subject to additional constraints on fishing for these species (Analysis, Section 1.9.1).
• Catch weighing and monitoring requirements. The original AFA in section 211(b)(6) imposed catch weighing and monitoring requirements on the 20 catcher/processors that were listed in the original AFA as eligible to harvest the directed pollock allocation of the catcher/processor sector. The original AFA required the listed catcher/processors to carry two NMFS observers at all times and to weigh all catch on NMFS-approved scales. Through regulations, the Council and NMFS developed catch measurement and observer requirements for all AFA catcher/processors, for AFA motherships, and for AFA catcher vessels (see regulations at § 679.51 and § 679.63).
The original AFA explicitly prohibited the replacement of original AFA vessels except under conditions specified in section 208(g) of the original AFA. The most stringent restriction in section 208(g) was that an owner of an AFA vessel could only replace an AFA vessel in the event of an “actual total loss or a constructive total loss” of the original AFA vessel. The original AFA did not specifically define total loss or constructive loss, but the terms are commonly used in maritime insurance. A total loss usually means that the vessel sinks, or is otherwise destroyed, and is physically lost. A constructive loss usually means that a vessel is so damaged that the cost of repair is greater than the value of the vessel. Thus, under the original AFA, a vessel owner could not replace an original AFA vessel until the AFA vessel sunk or was so damaged that it could not economically be repaired. An AFA vessel owner could not replace an original AFA vessel with another vessel simply because the vessel owner wanted a vessel that was safer, more fuel-efficient, or more operationally efficient than the owner's current vessel in any way.
Further, if an original AFA vessel owner did lose an original AFA vessel, section 208(g) of the original AFA limited the length, tonnage, and horsepower of the replacement vessel. If the original AFA vessel was a large vessel, the replacement vessel could not exceed the length, tonnage, or horsepower of the original AFA vessel. If the original AFA vessel was less than any of the statutory thresholds, the replacement vessel could exceed the length, weight, or horsepower of the original AFA vessel by 10 percent, but only up to the statutory thresholds for large vessels.
Between 1998 and passage of the Coast Guard Act in 2010, NMFS approved the replacement of four original AFA vessels under the standards in the original AFA. All
The original AFA had no explicit provisions on rebuilding original AFA vessels. The original AFA did not provide a mechanism for a vessel owner to remove an original AFA vessel from the directed pollock fishery.
To participate in the directed pollock fishery in the Bering Sea, an AFA vessel must not only have an AFA permit, but must also be named on an LLP license with a Bering Sea area endorsement. There are two sources for this requirement. First, section 208(a)(2) of the original AFA specifically stated that to be eligible to participate in the directed pollock fishery, a vessel had to be eligible to harvest pollock under the LLP. Second, pollock is a license limitation groundfish (§ 679.2) and to conduct directed fishing for any species of license limitation groundfish in the Bering Sea, a vessel must be named on an LLP groundfish license with a Bering Sea area endorsement (§ 679.4(k)(1)(i)).
Further, AFA vessels harvest pollock with trawl gear. Every LLP license has a gear designation of either trawl gear, trawl/non-trawl gear, or non-trawl gear (§ 679.4(k)(1)(iv)). The first two gear designations—trawl and trawl/non-trawl—authorize the vessel named on the LLP license to use trawl gear. Therefore, to effectively fish for pollock, an AFA vessel must have an LLP license with a gear designation for trawl gear or trawl/non-trawl gear.
The requirement that an AFA vessel have an LLP license limits the ability of owners of AFA vessels to rebuild or replace AFA vessels. All LLP licenses specify a maximum length overall or MLOA (§ 679.4(k)(3)(i)). Under existing regulations, a vessel fishing for groundfish pursuant to an LLP license cannot exceed the MLOA on that license (§ 679.4(k)(1)(i), § 679.7(i)(6)). Therefore, under existing LLP regulations, an AFA vessel can only fish for Bering Sea pollock if, after rebuilding or replacement, (1) the AFA vessel is designated on an LLP license with a Bering Sea area endorsement and a gear designation authorizing trawl gear and (2) the AFA vessel does not exceed the MLOA on that LLP license.
The original AFA applied to the directed pollock fishery in the entire BSAI Management Area (section 205(4), section 205(6), section 205(10) of original AFA). The BSAI Management Area consists of the Bering Sea Subarea and the Aleutian Islands Subarea (see regulatory definitions in § 679.2). In 2004, Congress adopted section 803 of Public Law 108-199, which was the Consolidated Appropriations Act, 2004. In this statute, Congress allocated the directed pollock fishery in the Aleutian Islands (AI) to the Aleut Corporation and specified criteria for vessels to be eligible to harvest that allocation. NMFS published regulations implementing this statute in 2005 (70 FR 9856, March 1, 2005).
Within statutory and regulatory restrictions, the Aleut Corporation may annually select the participants in this fishery (§ 679.4(m), § 679.20(a)(5)(iii)(B)(
On October 15, 2010, Congress amended the AFA in section 602 of the Coast Guard Act, Public Law 111-281. The Coast Guard Act revised section 208(g) of the AFA to essentially eliminate all restrictions on the ability of the owners of AFA vessels to rebuild or replace AFA vessels when the vessel participates in groundfish fisheries of the BSAI. Under the amended AFA, the owner of an AFA vessel may rebuild that vessel or replace that vessel in order to improve vessel safety and operational efficiencies, including fuel efficiency. The amended AFA removes the statutory limits on the length, tonnage, or horsepower of the rebuilt or replacement vessel when the rebuilt or replacement vessel is participating in BSAI groundfish fisheries. In addition, section 208(g) of the AFA, as revised, removes the MLOA limitation in the LLP on the length of an AFA rebuilt or replacement vessel when the vessel participates in BSAI groundfish fisheries.
With respect to the Gulf of Alaska (GOA), section 208(g)(6) of the AFA, as revised, preserves the MLOA limitation in the LLP on the length of an AFA vessel when the vessel participates in GOA groundfish fisheries. An AFA vessel—whether an original AFA vessel, a rebuilt AFA vessel, or a replacement AFA vessel—may not conduct directed fishing for groundfish in any area in the GOA if the vessel exceeds the MLOA on the LLP groundfish license that is endorsed for that area and that is assigned to that vessel.
With respect to participation in fisheries outside of Alaska, the original AFA in section 211(b)(5) prohibited an AFA catcher/processor or AFA mothership from harvesting or processing fish in any fishery outside of Alaska except the Pacific whiting fishery. The amended AFA in section 208(g)(1)(B) imposes that prohibition on rebuilt and replacement AFA catcher/processors and motherships because it subjects AFA rebuilt and replacement vessels to the same restrictions as the vessel being rebuilt or replaced. While the original AFA did not prohibit an AFA catcher vessel from harvesting fish in fisheries outside of Alaska, the amended AFA in section 208(g)(4) imposes a prohibition on AFA rebuilt or replacement catcher vessels similar to the prohibition that applied to AFA mothership vessels and listed AFA catcher/processors in section 211(b)(5) of the original AFA. Under the amended AFA, a rebuilt or replacement AFA catcher vessel is prohibited from harvesting fish in any fishery outside of Alaska except for the Pacific whiting fishery.
The provisions discussed thus far describe the fishing privileges of the AFA rebuilt vessel and the AFA replacement vessel. The other side of the coin is what happens to the vessel that is replaced: the vessel that leaves the AFA fishery and is replaced by another vessel in the AFA fishery. Under section 211(b)(5) of the amended AFA, a vessel that is replaced is not eligible for a Federal fishery endorsement under 46 U.S.C. 12113 unless the replaced vessel becomes, in the future, a replacement vessel for another vessel leaving the AFA fishery.
The amended AFA added section 210(b)(7) to the AFA. This new provision allows the owner of an AFA catcher vessel that is a member of an inshore cooperative to remove the
Finally, except for four named vessels, section 210(b)(7)(B) of the amended AFA prevents the owner of an AFA catcher vessel that is removed under this provision from using the removed vessel in other fisheries. The amended AFA accomplishes this by making a removed AFA catcher vessel permanently ineligible for a Federal fishery endorsement, except that a removed AFA vessel may receive a Federal fishery endorsement to reenter the AFA fishery as a replacement vessel.
The four vessels are named in section 210(b)(7)(C) of the amended AFA. These vessels, if removed, may receive a Federal fishery endorsement to participate in a fishery under the authority of the New England Fishery Management Council or the Mid-Atlantic Fishery Management Council. These vessels are the
The Coast Guard, in conjunction with MARAD, will issue Federal fishery endorsements in accord with the amended AFA. For information on the vessel documentation process, see the Coast Guard Web site for the National Vessel Documentation Center at
Section 208(g)(2) of the amended AFA gave the Council authority to recommend additional conservation and management measures if the Council concluded that such measures were necessary to ensure that the amended AFA did not undermine the effectiveness of the fishery management plans for either the BSAI or the GOA. Pursuant to section 208(g)(2) of the amended AFA, the Council reviewed whether to recommend conservation and management measures for the GOA, in addition to the restrictions on fishing by AFA vessels in the GOA in existing regulations. The Council concluded that additional measures for the GOA were not necessary, in light of the protections for GOA participants provided by current management measures.
The history of Council action on this subject is documented in minutes and newsletters of Council meetings, which are on the Council Web site:
At its February 2013 meeting, the Council reviewed the revised analysis. The Council approved the revised analysis for public review and adopted a preliminary preferred alternative. The Council's preliminary preferred alternative was Alternative 2, namely that NMFS should revise the relevant fishery management plans and regulations in accord with the AFA amendments, as NMFS planned to implement the AFA amendments, and that the Council did not need to recommend additional measures for the GOA. The other alternatives considered by the Council—Alternatives 2.1, 2.2, 2.3, and 2.4—placed additional restrictions on AFA rebuilt and replacement vessels when they participated in the GOA. At its April 2013 meeting, the Council unanimously adopted Alternative 2 as its preferred alternative.
In describing Alternative 2, the Analysis described how NMFS would implement the AFA amendments, if the Council did not recommend any additional conservation and management measures (Analysis, Executive Summary at pages ix-xv). The Analysis describes four key areas of NMFS' implementation of the AFA amendments under Alternative 2. First, under Alternative 2, the owner of an AFA vessel would be able to rebuild or replace the vessel with no limitation on the length, size, or horsepower of the rebuilt or replacement vessel, when the rebuilt or replacement vessel was participating in the BSAI (section 208(g)(1)(A) of amended AFA).
Second, with respect to the participation by AFA vessels in the GOA, the AFA amendments preserve the Maximum Length Overall (MLOA) restriction in the LLP for AFA rebuilt and replacement vessels when these vessels participate in the GOA (section 208(g)(6) of amended AFA). To participate in the GOA, AFA vessels must have an LLP license with an area endorsement for the Central Gulf or Western Gulf area (§ 679.4(k)(4)(ii)). An LLP license for the GOA may also have a Southeast Outside area endorsement but AFA vessels use trawl gear and trawl gear is prohibited in Southeast Outside (§ 679.22(b)(4)). Thus, under the AFA amendments as described in Alternative 2 in the Analysis, to fish for groundfish in the GOA, an AFA vessel 1) must have an LLP license with an area endorsement for Western Gulf or Central Gulf and 2) must not exceed the maximum length overall on that LLP license when the vessel is fishing pursuant to that license (Analysis, Executive Summary at page x). A vessel's LLP license endorsed for the Bering Sea is irrelevant to what the vessel can and cannot do in the GOA.
Third, the AFA amendments allow the owner of an AFA catcher vessel that is a member of an inshore cooperative to remove the vessel from the inshore cooperative and to assign the pollock fishing allowance of the removed vessel to one or more vessels in the same inshore cooperative (section 210(b)(7) of amended AFA). Fourth, and related, NMFS concludes that the AFA amendments require that NMFS extinguish any sideboard exemptions of a removed catcher vessel. The AFA amendments provide that, except for the claim to the pollock fishing allowance of the removed vessel, NMFS must extinguish “any claim (including relating to catch history)” of the removed vessel (section 210(b)(7)(B) of amended AFA). If the removed vessel was exempt from AFA sideboard limitations, the exemption was based on the vessel's catch history (§ 679.64(b)). A sideboard exemption is clearly a claim “relating to [the vessel's] catch history.” Therefore, if the removed vessel was exempt from sideboard limitations, the AFA amendments require NMFS to extinguish that exemption and prohibit NMFS from assigning that sideboard exemption to any other vessel or vessels. (Analysis, Executive Summary at page xv).
The Council specifically concurred with NMFS' interpretation of this provision in the AFA amendments (Analysis, Executive Summary at page
As for whether any other measures were necessary to protect the GOA, the Council concluded that no other measures were necessary. The Council noted the considerable protections already in place that restrict fishing by AFA vessels in the GOA. The Council relied on these measures to conclude that current management measures provided sufficient protection for participants in the GOA from increased activity from AFA rebuilt and replacement vessels.
The Analysis describes the existing limitations on AFA vessels in the GOA: the limited number of LLP licenses with Central Gulf or Western Gulf endorsements; the sideboard limits on GOA species that apply to most AFA vessels; the sideboard limits in the Central GOA Rockfish Program for AFA sideboard-exempt vessels that participate in that program; limitations on the use of AFA catcher vessels that operate in both the BSAI and GOA (commonly known as a “stand-down” requirement); exclusive fishing seasons for AFA catcher vessels that participate in the pollock fisheries in the BSAI and GOA; trip limits for pollock that are part of the Steller sea lion mitigation measures; limits on AFA trawl catcher vessels operating as pollock tenders; and the provision in the Inter-Cooperative Agreement that prevents an AFA-sideboard exempt vessel from leasing its pollock quota in a year once the vessel exceeds its GOA average harvest level from the 1995 through 1997 period (Analysis, Section 1.9.1 and Section 1.11.2).
A further restriction on AFA vessels in the GOA is the Pacific cod sector split. Beginning in 2012, NMFS annually allocates Pacific cod in the GOA by gear type and vessel type. The sector split allocates Pacific cod to the hook-and-line sector, the pot sector, and the trawl sector. Since AFA vessels use trawl gear to harvest pollock, and since the other gear sectors have their own Pacific cod allocation, the sector split restricts the harvest of Pacific cod in the non-trawl fisheries in the GOA by AFA vessels. For additional detail on the GOA Pacific cod sector split, see the final rule implementing this measure (76 FR 74670, December 2, 2011).
The Council relied on the current suite of restrictions on the participation by AFA vessels in the GOA when the Council did not adopt an alternative that limited participation by AFA vessels in the GOA beyond the restrictions in current statute and regulation.
As for the BSAI, and whether any additional measures were necessary to restrict fishing by AFA vessels in the BSAI, the Council did not specifically consider an alternative to limit non-pollock fishing by AFA rebuilt and replacement vessels in the BSAI beyond the restrictions currently in place. However, the Analysis presented to the Council did describe in detail the extent of fishing by AFA vessels in the BSAI in non-pollock fisheries and did describe the stringent sideboard limits and closures that restrict most AFA vessels (Analysis, Tables 1-1, 1-2, 1-5, 1-8, 1-9, 1-14, 1-15, 1-18. 1-19, 1-23, and Section 1.9.1).
The only AFA vessels that are exempt from any sideboard limits in the BSAI are 10 AFA catcher vessels that are exempt only from BSAI Pacific cod sideboard limits. These 10 sideboard-exempt vessels are, of course, subject to the TAC limits for BSAI Pacific cod and all other species they harvest. Furthermore, the AFA sideboard-exempt vessels in the BSAI are subject to many of the restrictions, noted above, that apply to AFA vessels in the GOA, including stand-down requirements for AFA catcher vessels that operate in both the BSAI and GOA; exclusive fishing seasons for AFA catcher vessels that participate in the pollock fisheries in the BSAI and GOA; and limits on AFA trawl catcher vessels from operating as pollock tenders (Analysis, Section 1.9.1 at pages 20-22).
Thus, with respect to the BSAI, the Council had before it considerable information regarding non-pollock fishing by AFA vessels in the BSAI and did not recommend any management measures beyond the limits on AFA vessels in existing regulations.
The BSAI FMP and current regulations are consistent with the original AFA, but not with the amended AFA. On this basis, the need for action is clear. The BSAI FMP and regulations must be changed to conform to a statute adopted by Congress.
This action is needed not only to implement the amended AFA, but also to further the purpose of the AFA amendments themselves. The primary purpose of the Coast Guard Act amendments to the AFA is to promote the safety and efficiency of the AFA fleet by allowing the owners of AFA vessels to rebuild or replace their vessels. Under the original AFA and existing regulations, an owner of an AFA vessel had to wait until the vessel sank or was damaged beyond repair before the owner of an AFA vessel could replace the AFA vessel with another vessel. The AFA fleet is aging. Of the 92 AFA catcher vessels active in the inshore and mothership sectors in 2011, all were built before 1992. Sixty were built before 1980 (Analysis, Table 1-7). Of the 21 catcher/processors with AFA permits, all were built before 1990. Fifteen were built before 1980 (Analysis, Table 1-26).
Under the original AFA, as reflected in current regulations, an owner of an AFA vessel cannot replace an AFA vessel with a vessel that is safer, more fuel efficient, or more operationally efficient in other ways. For example, the Analysis notes that advances in propulsion systems for catcher vessels, when paired with improved hull forms, can result in gains in fuel efficiency of up to 25 percent or more per pound of fish products delivered (Analysis, Section 1.11.2).
Under the original AFA, the rebuilding or replacement of AFA vessels was limited by length, tonnage, and horsepower of the rebuilt or replacement vessel. Under the amended AFA, the owner of an AFA vessel may rebuild that vessel or replace that vessel with no limit on the length, tonnage, or horsepower of the rebuilt or replacement vessel when the rebuilt or replacement vessel is participating in the BSAI. The removal of these limits could substantially improve the operational efficiency of AFA vessels. For example, the Analysis notes that the owners of smaller and older AFA catcher/processors may wish to rebuild or replace their vessels to install a fish meal plant, which would enable them to sell fish meal and fish oil. Vessels may also use fish oil as fuel in hybrid diesel electric engines and reduce costs from purchasing petroleum-based fuel (Analysis, Section 1.11.2).
The proposed rule would not require an AFA vessel owner to upgrade a vessel. An AFA vessel owner still must find that the improved safety and improved efficiency from rebuilding or replacing is worth the cost. The Analysis does not try to estimate how many owners of AFA catcher vessels, catcher/processors, or motherships will rebuild or replace vessels. The likelihood of a given vessel being rebuilt or replaced will depend on many factors, including the financial
Finally, this action responds to the problem that owners of catcher vessels in the inshore sector have experienced because the AFA had no provisions allowing for removal of vessels from the AFA fishery. Under existing regulations, the catcher vessels that do not actively fish for the cooperative must be tied up at the dock or put in storage, even if the owner has concluded that the vessel will never fish again. Except when a vessel was lost, the original AFA provided no way for the owner of an AFA inshore catcher vessel to transfer the catch history of one inshore catcher vessel to any other inshore catcher vessel. The owner of an AFA inshore catcher vessel could not do that simply because the owner wished to remove the vessel from the fishery.
The inability of the owner of an AFA inshore catcher vessel to remove a vessel from the AFA fishery results from the requirement in the original AFA and AFA regulations for a vessel to be a member of an inshore cooperative. For each year the owner of a catcher vessel wants to be a member of a particular inshore cooperative, the catcher vessel must be a “qualified catcher vessel” for membership in that inshore cooperative. (Original AFA, section 211(b)(3); 50 CFR 679.4(l)(6)(ii)(
Even though every catcher vessel in an inshore cooperative must be eligible to fish for pollock and for groundfish under the original AFA, not every catcher vessel in an inshore cooperative must actually fish for the cooperative. Some catcher vessels in a cooperative do not fish at all, or fish very little. Other, more efficient, catcher vessels in the cooperative harvest the pollock that the cooperative is authorized to catch. Some of the catcher vessels that do not fish are obsolete and inefficient, but under the original AFA and existing regulations, the owners of these vessels have no way to remove them from the AFA fishery. The AFA amendments and the proposed rule remedy this deficiency by allowing the owner of a catcher vessel that is a member of an inshore cooperative to remove that vessel from the AFA fishery subject to the conditions described above in Section II, “Summary of the AFA as amended by the Coast Guard Act.”
This proposed rule would revise the current regulations to implement the amended AFA and Amendment 106 to the BSAI FMP. This proposed rule addresses the rebuilding, replacement, and removal of AFA vessels and would make the following changes.
This proposed rule would establish the procedure for owners of AFA rebuilt vessels to maintain AFA permits on rebuilt vessels, would define the fishing privileges of the rebuilt vessel, and would modify the LLP regulations for AFA rebuilt vessels.
• Procedure. The proposed rule at § 679.4(l)(7)(i) would establish a procedure for the owners of AFA rebuilt vessels to maintain AFA permits for AFA rebuilt vessels. Under the proposed rule, an owner of an AFA vessel may rebuild the AFA vessel to improve the safety of the vessel or the operational efficiency of the vessel including the fuel efficiency of the vessel. When a vessel owner applies for an AFA permit or LLP license for a rebuilt vessel, NMFS will ask the applicant to certify that the purpose of the rebuilding was to improve safety, improve operational efficiency, or both.
In the application process, NMFS would not undertake to substantiate that the owner rebuilt the AFA vessel for the reason stated in the application. Similarly, NMFS would not undertake to substantiate through the application process that the rebuilt vessel was safer or more efficient. It would be difficult to establish a standard for judging whether a rebuilt or replacement vessel was safer or more efficient. NMFS does not believe that was the intent of Congress in amending the AFA. NMFS concludes that the purpose of the amended AFA is to allow the owner of an AFA vessel to weigh the considerable costs in rebuilding an AFA vessel against the benefits and to proceed if the owner determined the benefits were worth the costs.
To maintain an AFA permit, the AFA rebuilt vessel must have a certificate of documentation with a Federal fishery endorsement. If the owner of an AFA vessel rebuilds an AFA vessel, the proposed rule at § 679.4(l)(7)(i) would require that the owner notify NMFS and provide a copy of the documentation of the rebuilt vessel within 30 days of the issuance of the documentation. The 30-day period would provide adequate time for the applicant to notify NMFS.
• Fishing privileges of AFA rebuilt vessels. Under the proposed rule at § 679.4(l)(7)(i)(B), the owner of an AFA rebuilt vessel would be eligible to use the vessel in the same manner as the vessel before rebuilding and would be subject to the same requirements under 50 CFR part 679 that applied to the vessel before rebuilding, except for two requirements. First, under the proposed rule at § 679.4(l)(7)(i)(C), an AFA rebuilt vessel would be exempt from the MLOA requirement on an LLP groundfish license with a Bering Sea endorsement or an Aleutian Islands endorsement when that vessel is fishing for groundfish in the BSAI pursuant to that license, whether or not the vessel, before rebuilding, was exempt from the MLOA requirement. This exemption from the MLOA requirement for AFA rebuilt (and replacement) vessels implements a key feature of the AFA amendments.
The exemption from the MLOA requirement would attach to any AFA vessel that was rebuilt after October 15, 2010, the effective date of the Coast Guard Act. The exemption would remain with the vessel. That is, under the proposed rule, once an AFA vessel is rebuilt, the vessel would be permanently exempt from the MLOA restriction on any LLP license with a Bering Sea or Aleutian Islands area endorsement on which the vessel is designated when the vessel is fishing for groundfish in the BSAI pursuant to that LLP license.
The second area where an AFA rebuilt vessel would be subject to a different requirement from the AFA vessel before rebuilding relates to the fishing restrictions in § 679.23(i). A little background is necessary to understand the issue. For certain species in the BSAI or GOA, § 679.23 divides a fishing year into seasons. Section 679.23 divides directed fishing for pollock in the BSAI into two seasons (A season and B season) and divides directed fishing for pollock in the GOA into four seasons (A season, B season, C season, and D season). Section 679.23(i) imposes restrictions that prevent catcher
Section 679.23 is an inseason management tool to lessen competitive interactions between the groundfish fisheries and Steller sea lions. Section 679.23 “limits the concentration of fishing effort in one area and reduces the potential for localized depletion of Steller sea lion prey” (Analysis, section 1.9.1 at page 39). However, § 679.23(i) exempts catcher vessels that are less than 125 feet LOA from the season restrictions in the regulation when the vessels are fishing east of 157°00′ W. long.
NMFS considered whether an AFA rebuilt catcher vessel that is 125 feet LOA or greater after rebuilding would remain subject to the restrictions in § 679.23, even if the vessel was less than 125 feet LOA before rebuilding and therefore was not subject to the restrictions in § 679.23. Under the AFA amendments, NMFS concludes that an AFA rebuilt vessel that is 125 feet LOA or greater is subject to the restrictions in § 679.23. Thus, under the proposed rule at § 679.4(l)(7)(i)(D), an AFA rebuilt catcher vessel that is 125 feet LOA or greater would be subject to the fishing restrictions in § 679.23, even if the vessel before rebuilding was not subject to the restrictions in § 679.23.
NMFS bases this provision in the proposed rule—the continuation of the restrictions in § 679.23 on AFA rebuilt (and replacement) vessels—on three things: the language of the amended AFA, the purpose of the restrictions in § 679.23, and the Analysis for this action.
First, the amended AFA in section 208(g)(1)(A) states that “[n]otwithstanding any limitation to the contrary on replacing, rebuilding, or lengthening vessels, or transferring permits or licenses to a replacement vessel contained in section 679.2 and 679.4 [of Title 50 CFR],” a vessel owner may rebuild or replace an AFA vessel. The restriction in § 679.23 is not in § 679.2 or § 679.2 of Title 50 CFR and is therefore not abrogated by reference in section 208(g)(1)(A). Further, the restriction in § 679.23 is not a “limitation . . . on replacing, rebuilding or lengthening” AFA vessels. The proposed rule would still allow the owner of an AFA vessel to rebuild or replace an AFA vessel without limitation on the length of the vessel when it is fishing in the BSAI.
The amended AFA in section 208(g)(1)(B) states that the rebuilt and replacement vessel will be “subject to the same restrictions and limitations . . . as the vessel being rebuilt or replaced.” The amended AFA in section 208(g)(1)(C) states that the rebuilt and replacement vessel should receive the permits “as necessary . . . to operate in the same manner” as the vessel prior to rebuilding or replacement. If the AFA vessel, prior to rebuilding or replacement, had been lengthened so that it was 125 feet LOA or greater, the AFA vessel would have been subject to the restrictions in § 679.23. NMFS concludes that subjecting an AFA rebuilt vessel to the restrictions in § 679.23 is subjecting an AFA rebuilt vessel to “the same restrictions and limitations” that applied to the vessel before rebuilding and is allowing the AFA rebuilt vessel to “operate in the same manner” as the vessel could have operated before rebuilding.
Second, as noted, the purpose of § 679.23 is to lessen competition between the groundfish fisheries and the Steller sea lion population. NMFS concludes that the purpose of the AFA amendments was not to lessen the scope of the protective measures for the Steller sea lion population in § 679.23. Specifically, NMFS concludes that the purpose of the AFA amendments was not to grant more fishing opportunities to AFA vessels that become 125 feet LOA or longer through rebuilding as opposed to AFA vessels that are 125 feet or longer not as a result of rebuilding.
Finally, the Analysis describes the restrictions in § 679.23 on fishing by AFA vessels as part of Alternative 2, the Council's preferred alternative (Analysis, Section 1.9.1 at pages 39-40). In deciding not to recommend additional measures to limit AFA rebuilt and replacement vessels, the Council relied on this and other measures that currently limit the participation of AFA vessels in the BSAI and GOA. For these reasons, the proposed rule would keep in place the restrictions in § 679.23 that apply to AFA vessels that are 125 feet LOA or longer, even if the AFA vessel was less than 125 feet LOA before rebuilding.
• Changes in LLP regulations for AFA rebuilt vessels. The proposed rule would modify the LLP regulations at § 679.2 and § 679.4(k). The proposed rule modifies these regulations to provide that an AFA rebuilt vessel is exempt from the MLOA requirement on an LLP groundfish license with a Bering Sea or Aleutian Islands area endorsement assigned to the vessel when the vessel is fishing for groundfish in the BSAI and when the LLP license specifies the exemption.
The LLP license holder that wishes to designate an AFA rebuilt vessel on an LLP license is still subject to a limit of one voluntary transfer per year of an LLP license (§ 679.4(k)(7)(vi)). A change of the vessel designated on an LLP license is treated as a voluntary transfer of an LLP license (§ 679.4(k)(7)(vii)).
This proposed rule would establish the procedure for the owner of an AFA vessel to obtain an AFA permit for a replacement vessel, would define the fishing privileges of the replacement vessel, and would modify the LLP regulations for AFA replacement vessels.
• Procedure. Under the proposed rule at § 679.4(l)(7)(ii), an owner of an AFA vessel may replace an AFA vessel with another vessel to improve vessel safety or to improve operational efficiency, including fuel efficiency. To do that, the owner of an AFA vessel would have to submit an application to NMFS that would (1) identify a replacement vessel, (2) provide vessel documentation for the replacement vessel, (3) show that the replacement vessel has a Federal fishery endorsement, and (4) identify the LLP groundfish license on which the AFA replacement vessel would be designated.
On NMFS's approval of the application to replace the AFA vessel with another vessel, the AFA permit that designated the former, or replaced, vessel would be revoked and NMFS would issue a new AFA permit to the replacement vessel, unless the replacement vessel already had an AFA permit.
• Fishing privileges of AFA replacement vessels. The owner of the AFA replacement vessel would be eligible to use the AFA replacement vessel in the same manner as the AFA replaced vessel, and the AFA replacement vessel would be subject to the same requirements under 50 CFR part 679 that applied to the AFA replaced vessel, except for three requirements.
First, under the proposed rule at § 679.4(l)(7)(ii)(C), the AFA replacement vessel would be exempt from the MLOA on an LLP groundfish license with a Bering Sea or Aleutian Islands endorsement on which the replacement vessel is designated when the vessel is fishing pursuant to that LLP license, even if the replaced vessel was not exempt. As with AFA rebuilt vessels, the MLOA exemption would attach to a vessel that became an AFA replacement vessel after October 15, 2010, the
Second, under the proposed rule at § 679.4(l)(7)(ii)(D), an AFA replacement vessel that exceeds 125 feet LOA would be subject to the fishing restrictions in § 679.23(i), even if the replaced or departing vessel was less than 125 feet and was exempt from these restrictions. This is the same provision that would apply to AFA rebuilt vessels under the proposed rule. The rationale for this provision is thoroughly explained in the previous section, “Fishing Privileges of AFA rebuilt vessels.”
Third, under the proposed rule at § 679.4(l)(7)(ii)(E), if the AFA replacement vessel was already an AFA-permitted catcher vessel with a sideboard exemption, and the replaced or departing vessel was an AFA catcher vessel without a sideboard exemption, the replacement vessel would maintain the sideboard exemption. The replacement vessel would not lose an exemption by virtue of acquiring the pollock catch history of a vessel that did not have an exemption.
• Changes in LLP regulations for AFA replacement vessels. As with AFA rebuilt vessels, the proposed rule would modify the LLP regulations at § 679.2 and § 679.4(k). The proposed rule would modify these rules to provide that an AFA replacement vessel is exempt from the MLOA requirement on an LLP groundfish license with a Bering Sea or Aleutian Islands area endorsement assigned to the vessel when the AFA replacement vessel is fishing for groundfish in the BSAI pursuant to that LLP license and when the LLP license specifies the exemption.
The LLP license holder that wishes to designate an AFA replacement vessel on an LLP license is still subject to the limit in current regulation of one voluntary transfer per year of an LLP license (§ 679.4(k)(7)(vi)). A change of the vessel designated on an LLP license is treated as voluntary transfer of an LLP license (§ 679.4(k)(7)(vii)).
• Fishing privileges of AFA replaced vessels. The replaced vessel is the AFA vessel that has left the AFA fishery and is replaced by another vessel. Under the amended AFA at section 208(g)(5), the replaced vessel is not eligible for a Federal fishery endorsement unless, at some point in the future, the replaced vessel reenters the AFA fishery as a replacement vessel. Thus, the only fishing activity possible for a replaced vessel is reentering the AFA fishery as a replacement vessel.
While the provisions explained above apply generally to rebuilding and replacing AFA catcher/processors, motherships, and catcher vessels, the proposed rule includes specific measures that apply to (1) the rebuilding or replacement of AFA catcher vessels with sideboard exemptions; (2) the replacement of vessels in AFA inshore cooperatives; (3) the status of AFA permits after a vessel is lost; and (4) how the owners of lost catcher AFA vessels may participate in AFA inshore cooperatives. Before examining the provisions in the proposed rule on removing AFA catcher vessels, NMFS will discuss these four special situations regarding rebuilding and replacing AFA vessels.
Under current regulations, AFA catcher vessels are subject to sideboard limitations in the BSAI groundfish fisheries and in the GOA groundfish fisheries, unless an AFA catcher vessel met requirements in § 679.64(b)(2) for an exemption. The regulation provides for an exemption in the BSAI only from BSAI Pacific cod sideboards, not from sideboard limits for any groundfish other than BSAI Pacific cod. The regulation provides for an exemption in the GOA from sideboards for all groundfish species.
In the original AFA, the requirements for initial eligibility for an AFA vessel to be exempt from BSAI Pacific cod sideboard limits were that an AFA catcher vessel (1) was under 125 feet LOA; (2) harvested a relatively small amount of BSAI pollock between 1995 and 1997 (5,100 metric tons); and (3) made a fairly high number of landings of BSAI Pacific cod (30 or more) in that same time period (§ 679.4(l)(3)(ii)(
The requirements for initial eligibility for an AFA vessel to be exempt from GOA groundfish sideboard limits were that an AFA catcher vessel (1) was under 125 feet LOA; (2) harvested a relatively small amount of BSAI pollock between 1995 and 1997 (5,100 metric tons); and (3) made a fairly high number of landings of GOA groundfish (40 or more) in that same time period (§ 679.4(l)(3)(ii)(
Ten AFA catcher vessels met the requirements for an exemption from BSAI Pacific cod sideboard limits and 16 AFA catcher vessels met the requirements for an exemption from GOA groundfish sideboard limits (Analysis, Section 1.9.1). The regulations also exempt from BSAI Pacific cod sideboard limits a category of AFA catcher vessels regardless of the length of the vessel; namely, AFA catcher vessels that deliver to motherships are exempt from BSAI Pacific cod sideboard closures after March 1 of the fishing year (§ 679.64(b)(2)(i)(B)).
Under the proposed rule at § 679.4(l)(7), the owner of an AFA catcher vessel after rebuilding or replacement would be eligible to participate in the same manner as the vessel before rebuilding or replacement. This means that the owner of an AFA catcher vessel that is exempt from sideboard limits may rebuild or replace the AFA catcher vessel and maintain the exemption from sideboard limits, even if the rebuilt or replacement vessel exceeds the initial eligibility criterion that the vessel be less than 125 feet LOA. This aspect in the proposed rule—the continuation of sideboard exemptions for AFA replacement and rebuilt vessels—implements the language of the amended AFA; was part of Alternative 2, the Council's preferred alternative; and furthers the purpose of the amended AFA.
First, in the amended AFA, section 208(g)(1)(A) states that the expanded privilege for rebuilding and replacing AFA vessels is “[n]otwithstanding any limitation to the contrary on replacing, rebuilding, or lengthening vessels or transferring permits or licenses to a replacement vessel contained in sections 679.2 and 679.4.” The requirements for initial eligibility for a sideboard exemption are in § 679.4, which supports the conclusion that an AFA vessel owner should be able to replace, rebuild, or lengthen without being subject to this limitation.
The amended AFA in section 208(g)(1)(B) states that the rebuilt or replacement vessel “shall be eligible to operate in the same manner and subject to the same restrictions and limitations” as the vessel before rebuilding or the vessel before replacement. The amended AFA states in section 208(g)(1)(C) that “[e]ach fishing permit and license held by the owner of the vessel or vessels to be rebuilt or replaced . . . shall be transferred to the rebuilt or replacement vessel or its owner, as necessary to permit such rebuilt or replacement vessel to operate in the same manner as the vessel prior to the rebuilding or the vessel it replaced, respectively.” Under the amended AFA and this proposed rule, an AFA rebuilt or replacement catcher vessel would maintain an exemption from sideboard closures so as to allow the vessel “to operate in the same manner” as the vessel did prior to rebuilding or replacement, notwithstanding the limitation in § 679.4 that an AFA vessel must be less than 125 feet LOA to have an exemption from sideboards.
Second, this provision in the proposed rule—continuation of sideboard exemptions for AFA rebuilt or replacement vessels—was part of Alternative 2, the Council's preferred alternative. Under Alternative 2, as explained in the Analysis, an AFA rebuilt or replacement vessel would have sideboard exemptions if the vessel before rebuilding, or if the vessel that was being replaced, had exemptions (Analysis, Executive Summary at page ix).
Finally, the continuation of sideboard exemptions for AFA rebuilt or replacement vessels furthers the primary purpose of the AFA amendments, which is to allow the owners of AFA vessels to rebuild and replace AFA vessels in accord with their determination that the costs of rebuilding and replacing are worth the benefits. The proposed rule would allow the owner of an AFA catcher vessel that is exempt from AFA sideboards to determine whether to rebuild or replace the vessel based on the costs and benefits of rebuilding and replacing. The proposed rule would not make the owners of AFA sideboard-exempt vessels choose between rebuilding/replacing their vessels andcontinuing to operate with an exemption from sideboard limits.
However, with respect to AFA vessels that are exempt from GOA groundfish sideboard limits, the amended AFA and this proposed rule would preserve the requirement that an AFA vessel may not fish for groundfish in any area in the GOA if the AFA vessel exceeds the MLOA on the vessel's LLP license endorsed for the GOA. This is a very significant constraint on the length of AFA vessels that may operate in the GOA. Although 16 AFA vessels are exempt from sideboard limitations in the GOA, there is only one LLP groundfish license with a Central Gulf area endorsement for a trawl catcher vessel that exceeds 125 feet LOA and that vessel may not exceed 149 feet LOA. There are no LLP groundfish licenses with a Western Gulf area endorsement for a trawl catcher vessel that exceeds 125 feet LOA (Analysis, Table 1-51). Thus, under the proposed rule, only one AFA catcher vessel could exceed 125 feet LOA and operate in the GOA with an exemption from AFA sideboard limits, and that vessel could not be longer than 149 feet LOA.
NMFS issues AFA inshore cooperative fishing permits annually to inshore cooperatives. The AFA inshore cooperative fishing permit displays the amount of pollock the inshore cooperative is authorized to harvest for the upcoming fishing year. The permit displays this amount as a percentage of the Bering Sea pollock allocation. NMFS determines this amount by adding together the pollock that each catcher vessel member of the cooperative may harvest. Under the proposed rule, when the owner of a catcher vessel that is a member of an inshore cooperative replaces that vessel, the replacement vessel would be eligible to join the same inshore cooperative of which the replaced vessel was a member. NMFS would transfer the catch history of the replaced vessel to the replacement vessel.
The proposed rule would not change the current deadline for the annual application for an inshore cooperative permit. NMFS still must receive the inshore cooperative application for the upcoming fishing year by December 1 of the prior year. The cooperative application must still list all vessels that are members of the cooperative. And a cooperative will continue to be prohibited from adding or subtracting a vessel for the upcoming fishing year after December 1 of the prior year (§ 679.4(l)(6)(iv), § 679.4(l)(6)(v)). The purpose of the December 1 deadline is to allow NMFS to calculate the allocations for the upcoming year for each cooperative and for the open access sector, if any vessels are in open access.
The December 1 deadline would not apply to applications to replace or remove vessels pursuant to the replacement/removal procedure in this proposed rule. A vessel owner may apply to do that at any time. The replacement or removal of a vessel in an inshore cooperative would not interfere with NMFS' annual calculations for the inshore sector. If NMFS approves the replacement of one vessel that is a member of an inshore cooperative with another vessel, NMFS would not have to change the pollock allocations to the cooperatives. Similarly, if NMFS approves removal of a vessel from an AFA inshore cooperative and assigns the catch history of the removed vessel to one or more vessels in the same cooperative, NMFS would not have to change the allocations to the cooperatives.
The proposed rule addresses the situation of owners of AFA vessels who experience a total or constructive loss of their vessel. The amended AFA completely revised section 208(g) of the original AFA, which had allowed the owner of AFA vessel to replace the vessel only if it was lost. Section 208(g) of the amended AFA allows the owner of an AFA vessel to replace or rebuild the vessel at any time to improve safety or efficiency.
Under section 208(g) of the original AFA, the owner of an AFA vessel had 36 months from the end of the last year in which the AFA vessel harvested or processed pollock to replace a lost AFA vessel. The original AFA was silent as to the privileges of the owner of a lost AFA vessel during that period and silent as to the privileges of the owner of the lost AFA vessel after that period had lapsed if the owner did not replace the AFA vessel during the allotted time.
The amended AFA also did not explicitly address what happens to the AFA fishing privileges of a lost vessel between the time that the owner loses the vessel and the owner replaces the vessel. To implement the amended AFA, and to provide clarity to the public, the proposed rule specifies the status of an AFA permit in the event of a total or constructive loss of an AFA vessel. NMFS specifically welcomes comment on this provision.
NMFS examined three options. The first option would provide that in the event of a total or constructive loss of an AFA vessel, the AFA permit that designates the lost vessel would immediately become invalid and the owner of the lost AFA vessel would have no AFA fishing privileges until the owner replaces or removes the lost vessel under the replacement/removal procedures in the proposed rule. This approach would pressure the owner of the lost AFA vessel to immediately replace or remove the lost vessel.
The second option would provide that in the event of a total or constructive loss of an AFA vessel, the AFA permit would remain valid until the AFA permit holder designated a replacement vessel. This option would have no mechanism that required the AFA permit holder to designate a replacement vessel and would change the AFA permit from a permit tied to a specific vessel to a permit that was not tied to a vessel. NMFS believes the amended AFA was not meant to fundamentally change the nature of the AFA permit in this way.
The third option would provide that in the event of total or constructive loss of an AFA vessel, the AFA permit would remain valid for a reasonable, but not unlimited, period of time to allow the owner of the lost AFA vessel to continue to receive privileges under the AFA without immediately having to designate a replacement vessel. The proposed rule would implement this
NMFS determined that a reasonable period of time for the vessel owner to replace a lost vessel or, in the case of an AFA catcher vessel in an inshore cooperative, to remove a lost vessel, is the same period of time that was in the original AFA: the time period starting on the date of the vessel loss and ending on December 31 of the year that is 3 years (36 months) after the year in which the vessel was lost (section 208(g)(3) of the original AFA). It is easier to understand by example. Under the proposed rule at § 679.4(l)(ii), if a vessel sinks on February 15, 2016, the AFA permit on the lost vessel would be valid until December 31, 2019, unless the vessel owner has been issued an AFA permit on a replacement vessel before December 31, 2019, or the vessel owner has removed the lost vessel before that date. For ease of reference, this preamble refers to this time period as a “3-year period,” although technically it is a “3-year plus time period” because the AFA permit remains valid until December 31 of the year in which the vessel was lost and then 3 more years after that.
NMFS believes that a 3-year period would provide a vessel owner with adequate time to decide whether to replace or remove a lost vessel and to apply to take one of those actions. As noted, this 3-year period is the same period of time that the original AFA in section 208(g) gave the owner of an original AFA vessel to replace an AFA vessel. This 3-year period was adequate for the replacement of four AFA vessels that were lost before enactment of the Coast Guard Act.
Under the proposed rule, NMFS would revoke the AFA permit that designated the lost vessel if, before the end of the 3-year period if, during that period, the owner of the AFA vessel replaces the lost vessel with another vessel or removes the lost vessel pursuant to the replacement/removal procedures established by the proposed rule. It would be inconsistent with the AFA to have two AFA permits authorizing two AFA vessels to fish based on the fishing history of the same lost vessel.
If, at the end of the 3-year period, the AFA vessel owner had not replaced or removed the lost AFA vessel, NMFS would suspend the AFA permit that designated that lost vessel and the AFA permit would not be valid. Since NMFS may have to suspend the AFA permit, the proposed rule would require that the owner of an AFA vessel notify NMFS within 120 days after the vessel is lost.
After the permit was suspended, the owner of the lost AFA vessel could still apply to replace or remove the lost vessel that was designated on the AFA permit. But while the permit was suspended, the owner of the lost AFA vessel would not have a valid AFA permit and would have no fishing privileges based on the suspended AFA permit.
For several reasons, NMFS believes it is highly unlikely that any AFA permits would be suspended under this provision. The permits are valuable. The AFA permit holders have operated in a highly regulated fishery since 1998. And since AFA vessels almost always fish as members of cooperatives, the other members of the cooperative and the cooperative manager would have a great interest in making sure a member's AFA permit is not suspended.
The original AFA in section 208(g) recognized two types of vessel loss that allowed the owner of an AFA vessel to replace an AFA vessel: total loss of the AFA vessel or constructive loss of the AFA vessel. The proposed rule also recognizes these two types of vessel loss. The proposed rule would define total loss and constructive loss for purposes of determining the validity of AFA permits and would clarify when the time period for replacing or removing a vessel would begin. The proposed rule would define total loss and constructive loss in § 679.4(l)(1)(ii)(B)(
The proposed rule would define the date of the total loss of the vessel as the date when the vessel was physically lost. The proposed rule would define the date of the constructive loss of the vessel as the date when the vessel suffered the damage that resulted in the cost of repair exceeding the value of the vessel.
The proposed rule addresses how NMFS would evaluate an application for an inshore cooperative fishing permit if the applicant includes the catch history of a lost catcher vessel. In examining this provision, it is helpful to keep in mind the standard requirements for a vessel to be a member of a particular cooperative. To be a member of an inshore cooperative, a catcher vessel must meet permit requirements and landing requirements (§ 679.4(l)(6)(ii)(D)(
The landing requirements are specific to each cooperative. Each cooperative designates a particular AFA inshore processor to which the cooperative members have agreed to deliver at least 90 percent of their pollock catch (§ 679.4(l)(6)(i)(B)). To be a member of a particular cooperative, the catcher vessel must have delivered more pollock to the processor associated with that cooperative than to any other processor during the prior year or, if the vessel is inactive, during the last year that the vessel made pollock deliveries (§ 679.4(l)(6)(ii)(D)(2)). This means that if a catcher vessel wishes to switch to a new cooperative, the catcher vessel must first spend a year in the open access sector and, for that year, deliver more fish to the processor associated with the new cooperative than to any other processor. After that year, the catcher vessel could join the new cooperative.
As described earlier, under the proposed rule, if an AFA vessel is lost, the AFA permit that designated the lost catcher vessel would be valid for up to 3 years from December 31 of the year in which the vessel was lost. As a corollary to that provision, the proposed rule would establish at § 679.4(l)(6)(ii)(D)(
The proposed rule would establish which inshore cooperative that the owner of a lost AFA catcher vessel may join during this 3-year period. The proposed rule would do this by adding a provision to the inshore cooperative permit regulation at § 679.4(l)(6)(ii)(D)(
In the unlikely event that a catcher vessel is lost during a year when the catcher vessel was not a member of an inshore cooperative, but the vessel had made deliveries to an AFA inshore processor during that year before the vessel was lost, the owner of the lost vessel would be allowed to join the inshore cooperative that is associated with the processor to which the vessel delivered more pollock than any other processor during that year.
In both these situations—when the lost catcher vessel was a member of a cooperative and when the lost catcher vessel was in the open access sector but had made deliveries to a processor associated with a cooperative—the proposed rule would not allow the owner of the lost vessel to join a different cooperative. This limitation is in keeping with the AFA cooperative structure and the landing requirements to be a member of a cooperative (§ 679.4(l)(6)(ii)(D)(
In the very unlikely event that a catcher vessel is lost during a year when the vessel was not designated on an inshore cooperative permit, and before the vessel made any pollock deliveries, the owner of the lost vessel would be permitted to join any inshore cooperative while the AFA permit designating the lost vessel was valid.
NMFS notes that it is rare that vessels are lost. From 1998 to 2010, NMFS is aware of only four AFA vessels that were lost. And it is very rare that an inshore catcher vessel is not a member of an inshore cooperative. As noted earlier, since 2004, only two inshore vessels have not fished as a member of a cooperative and that was only for one year (2010). Thus, even though the proposed rule addresses the possibility that a catcher vessel would be lost, and that the lost catcher vessel would not be a member of a cooperative, it is quite unlikely this will occur. If an inshore catcher vessel is lost, in all likelihood, it would be completely straightforward what cooperative the owner of the lost catcher vessel may join during the 3-year period when the permit may remain valid. It would be the cooperative of which the lost catcher vessel was a member.
The proposed rule at § 679.4(l)(7)(iii) would allow the owner of an AFA catcher vessel that is a member of an inshore cooperative to remove that vessel from the AFA fishery and assign the Bering Sea pollock catch history of the removed vessel to one or more catcher vessels within the cooperative subject to four conditions that NMFS would administer. Each of these conditions is required by section 210(b) of the amended AFA.
First, under the proposed rule at § 679.4(l)(7)(iii)(B), the owner of the AFA catcher vessel that is being removed would be required to direct NMFS to assign the catch history of the removed catcher vessel to one or more AFA catcher vessels that are members of the inshore cooperative to which the removed vessel belonged as of the date that the vessel owner submitted an application for removal. If the owner of the AFA catcher vessel directs NMFS to assign the catch history of the removed vessel to more than one vessel, the owner would be required to specify the percentage of catch history that would be assigned to each vessel. The proposed regulation would not allow the catch history of the removed vessel to be free-floating, or unassigned. The catch history must be assigned to one or more vessels in the cooperative to which the removed vessel belonged. The approval by NMFS of removing a catcher vessel and the assignment by NMFS of the catch history to another vessel or vessels would occur at the same time.
Second, except for assigning the inshore pollock catch history, NMFS would permanently extinguish all other claims relating to the catch history of the removed vessel. The proposed rule at § 679.4(l)(7)(C) includes this provision. Specifically, under the proposed rule, if an AFA catcher vessel is exempt from an AFA sideboard limitation, and that vessel is removed from the AFA fishery, NMFS would permanently extinguish that sideboard exemption and would not assign the exemption to any other vessel or vessels in the inshore cooperative.
Third, under the proposed rule at § 679.4(l)(7)(iii)(D), the vessel or vessels that are assigned the catch history of the removed vessel—the receiving vessel or vessels—could not themselves be removed from the cooperative for one year from the date on which the receiving vessel or vessels were assigned the catch history of the removed vessel. For example, under the proposed rule, if NMFS approved the assignment of catch history of a removed vessel to a receiving vessel on July 1, 2016, the receiving vessel could not be removed from the cooperative until July 1, 2017.
Fourth, under the proposed rule at § 679.4(l)(7)(iv), a vessel that is removed would be permanently ineligible to receive any permits to operate in the Exclusive Economic Zone (EEZ) off Alaska unless, after being removed, the removed vessel reenters the AFA fishery as a replacement vessel for another vessel. This is based on section 210(b)(7)(B), which states that removal of a catcher vessel from an inshore cooperative extinguishes “any claim (including relating to catch history) associated with such vessel that could qualify any owner of such vessel for any permit to participate in the exclusive economic zone of the United States.” While the proposed rule would prohibit participation by a removed vessel in the EEZ off Alaska, it is important to note that section 210(b)(7)(B) prohibits participation by a removed vessel in the entire United States EEZ.
NMFS has created one form that would be used by the owners of AFA vessels that rebuild, replace, or remove their AFA vessels: “American Fisheries Act (AFA) Permit: Rebuilt, Replaced, or Removed Vessel Application.” The application and instructions would be published on the NMFS Alaska Region Web site at
After NMFS receives a complete application, NMFS would take the action requested by the applicant if the applicant met the requirements for NMFS to take the action. If the
If the applicant seeks to replace an AFA vessel, NMFS would issue a new AFA permit to the replacement vessel, unless the replacement vessel already is designated on an AFA permit. NMFS would revoke the AFA permit on the former, or replaced, AFA vessel. On the application form, the AFA vessel owner would indicate the LLP license on which the AFA replacement vessel would be designated. NMFS would issue to the AFA replacement vessel an LLP groundfish license with an exemption from the MLOA restriction. The exemption would only be valid when the AFA replacement vessel is used to fish for groundfish in the BSAI pursuant to that LLP license. If the applicant seeks to replace an AFA catcher vessel with an inshore endorsement, NMFS would modify the AFA permit of the replacement vessel so that the replacement vessel has the exemptions from sideboard limitations, if any, of the replaced vessel.
If the applicant seeks to remove an AFA catcher vessel with an inshore endorsement, NMFS would assign the pollock catch history of the removed vessel to one or more vessels in the inshore cooperative to which the removed vessel belonged, in accord with the application of the owner of the removed vessel. NMFS would notify the applicant that the AFA permit designating the removed catcher vessel was revoked and that, except for the reassigned pollock history, NMFS had extinguished all claims related to the catch history of the removed vessel, including any claims to exemptions from sideboard limitations.
If NMFS believes that the application is deficient, NMFS would notify the applicant and give the applicant one 30-day period to remedy the deficiencies in the application. After the 30-day period, NMFS would review the application and any information submitted within the 30-day period. NMFS would either grant the application or deny the application by issuing an Initial Administrative Determination (IAD), which would explain the basis for the denial.
Under the proposed rule at § 679.4(l)(8)(iii), an applicant would be able to appeal the denial of an application pursuant to the appeal procedures at 15 CFR part 906. NMFS has established a National Appeals Office (NAO) located at NMFS Headquarters in Silver Spring, Maryland. In 2014, NMFS adopted rules of procedure for NAO appeals in 15 CFR part 906. (Final Rule, 79 FR 7056 (Feb. 6, 2014)). The appeal procedures in 15 CFR part 906 are mandatory for appeals in limited access privilege programs (LAPPs) under section 303A of the Magnuson-Stevens Act. 15 CFR 906.1(b). Section 303A applies only to limited access privilege programs that were adopted after January 12, 2007, the date of enactment of the Magnuson-Stevens Fishery Conservation and Management Reauthorization Act of 2006. 16 U.S.C. 1853a. The AFA was adopted on October 21, 1998. Therefore, AFA appeals are not required to be heard under the procedural rules at 15 CFR part 906.
NMFS may, however, request that NAO decide appeals in programs where NAO does not have mandatory jurisdiction. 15 CFR 906.1(d). In the proposed rule, NMFS proposes to use NAO for appeals of initial administrative determinations issued under this rule and to adopt 15 CFR part 906 as the procedural rules for AFA appeals.
In the past, NMFS Alaska Region had its own appeals office and its own procedural rules for appeal in 50 CFR 679.43. NMFS Alaska Region no longer has its own appeals office and therefore is opting to use the NAO and the procedural rules for the NAO.
In developing this proposed rule, NMFS identified an error in the definition of mothership in 50 CFR 679.2. The current regulation states: “AFA mothership means a mothership permitted to process BS pollock under § 679.4(l)(5).” Section 679.4(l)(5) is “AFA inshore processor permits.” Section 679.4(l)(4) is “AFA mothership permits.” NMFS therefore proposes to change the definition of mothership in § 679.2 to state: “AFA mothership means a mothership permitted to process BS pollock under § 679.4(l)(4).”
Pursuant to section 304(b)(1)(A) and 305(d) of the Magnuson-Stevens Act, the NMFS Assistant Administrator has determined that this proposed rule is consistent with the BSAI FMP, other provisions of the Magnuson-Stevens Act, and other applicable law, subject to further consideration of comments received during the public comment period.
The proposed rule has been determined to be not significant for purposes of Executive Order 12866.
A Regulatory Impact Review/Initial Regulatory Flexibility Analysis was prepared. An Initial Regulatory Flexibility Analysis (IRFA) was prepared as required in section 603 of the Regulatory Flexibility Act (RFA). On June 20, 2013, the Small Business Administration issued a final rule revising the small business size standards for several industries effective July 22, 2013 (78 FR 37398, June 20, 2013). The rule increased the size standard for Finfish Fishing from $4.0 to 19.0 million, Shellfish Fishing from $4.0 to 5.0 million, and Other Marine Fishing from $4.0 to 7.0 million. Id. at 37400 (Table 1). The new size standards were used to prepare the IRFA for this action.
The IRFA describes the economic impact this proposed rule, if adopted, would have on small entities. A description of the action, why it is being considered, and the legal basis for this action are contained under the heading “Need for Action” in the preamble and in the
This action would regulate the owners of vessels that are designated on AFA permits; these vessels are catcher vessels, catcher/processor vessels, and motherships. In 2013, 105 catcher vessels, 21 catcher/processors, and 3 motherships were designated on AFA permits (Analysis, Section 2.4). In assessing whether an entity is small, the RFA requires NMFS to consider affiliations between entities.
With respect to AFA catcher/processors, the IRFA states: “All AFA catcher/processors are affiliated through membership in the Pollock Conservation Cooperative; the members of this cooperative had estimated 2012 gross revenues from pollock alone in excess of $500 million. Thus these are large entities.” (Analysis, Section 2.4, footnote omitted).
With respect to catcher vessels, the IRFA states: “All AFA catcher vessels are members of one of eight cooperatives delivering pollock to inshore processing plants, to motherships, or to catcher/processors. The cooperative of catcher vessels delivering to catcher/processors was closely affiliated with the catcher/processor cooperative, and thus the member entities are large. The seven cooperatives delivering to processing
With respect to AFA motherships, the IRFA states: “Three motherships accept deliveries of pollock from catcher vessels. While these vessels are authorized to join the cooperative of catcher vessels making such deliveries, they have not recently chosen to do so. However, each of these motherships is believed to be a large entity, based on corporate affiliations with other large processing firms.” (Analysis, Section 2.4).
Thus, the IRFA concluded that all of the entities regulated by this action are “large” entities for the purpose of the RFA. If that is so, NMFS need not have prepared an IRFA for this proposed rule because an IRFA is necessary only to evaluate the impact of a proposed rule on small entities. NMFS prepared an IRFA, however, because the IRFA acknowledged that the data on ownership and affiliation of AFA entities was limited.
This action imposes one additional reporting requirement on the owner of an AFA rebuilt vessel. If the owner of an AFA vessel rebuilds an AFA vessel, the owner shall submit the documentation for the rebuilt vessel to NMFS within 30 days of the issuance of the documentation.
Apart from this requirement, the owners of AFA rebuilt vessels would be subject to the same recordkeeping and reporting requirements after rebuilding as before rebuilding. Similarly, the owners of AFA replacement vessels would be subject to the same recordkeeping and reporting requirements that applied to the replaced, or former, AFA vessel. If a vessel is removed, the owners of the AFA vessels that are assigned the catch history of the removed vessel would be subject to the same recordkeeping and reporting requirements after they are assigned the catch history of the removed vessel as before they were assigned the catch history of the removed vessel.
NMFS has created an application form for the owner of an AFA vessel who wishes to take any of the actions allowed by this rule. The application form allows the owner of an AFA vessel to notify NMFS of rebuilding, to request to replace an AFA vessel, or to remove an AFA vessel.
This proposed rule is necessary because existing rules conflict with the AFA amendments in the Coast Guard Act. Apart from that conflict, NMFS has not identified any duplication, overlap, or conflict between this proposed action and existing Federal rules.
Section 603 of the RFA requires that NMFS should describe any significant alternatives to the proposed action that would accomplish the stated objectives of applicable statutes and would minimize any significant adverse economic impacts on small entities. Although the IRFA concluded that this action did not directly regulate any small entities, the Council and NMFS assumed, for the purpose of the IRFA, that the directly regulated entities were small entities and considered the potential effects on the directly regulated entities.
The Council considered Alternative 1; Alternative 2; and Alternatives 2.1, 2.2, 2.3, and 2.4. Alternative 1 was no action. The Council did not adopt Alternative 1 because it did not conform regulations and the BSAI FMP to a statute adopted by Congress, namely the AFA amendments in the Coast Guard Act. Alternative 1 continued the stringent restrictions in current regulation on the ability of the owners of AFA vessels to upgrade their vessels through rebuilding or replacing the vessels. Alternative 1 continued the prohibition in current regulation on the owners of AFA catcher vessels from removing their vessels and assigning the catch history of their vessels to other vessels in their cooperatives. Alternative 1 completely contradicted the objectives of the amended AFA.
Under Alternative 2, “the status quo” alternative, fishery management plans and existing regulations would be changed to conform to the AFA amendments, as NMFS interprets the AFA amendments. The Council and NMFS concluded that the BSAI FMP was inconsistent with the AFA amendments. The Council and NMFS therefore proposed amending the BSAI FMP with Amendment 106 to the BSAI FMP. The Council and NMFS concluded that the GOA FMP was consistent with the amended AFA and therefore proposed no change to the GOA FMP.
Alternative 2 would change the BSAI FMP and implementing regulations to allow the owners of AFA vessels to participate in the BSAI with a rebuilt or replacement vessel without limit on the length, tonnage, or horsepower of the rebuilt or replacement vessel. Alternative 2 continues all the restrictions currently in place on participation by AFA vessels in the GOA, including the requirement that an AFA vessel may not participate in the GOA unless the vessel has an LLP license and the vessel does not exceed the MLOA on that license. The Council selected Alternative 2 as its preferred alternative.
Alternatives 2.1, 2.2, 2.3, and 2.4 would have imposed additional restrictions on participation by AFA rebuilt and replacement vessels in the GOA, in addition to restrictions in current regulations (Analysis, Executive Summary). Alternative 2.1 stated that an AFA rebuilt and replacement vessel that is subject to sideboards could not participate in the GOA if the vessel exceeded the most restrictive MLOA on any GOA LLP license assigned to the vessel at the time that the vessel owner applied to NMFS to replace or rebuild the AFA vessel. Alternative 2.2 stated that an AFA rebuilt or replacement vessel that is subject to sideboards could not participate in the GOA if the vessel exceeded the most restrictive MLOA on any GOA LLP license assigned to the vessel on October 15, 2010, the date of passage of the Coast Guard Act. Alternative 2.3 stated that an AFA rebuilt or replacement vessel that is subject to sideboards could not participate in the GOA if the AFA rebuilt or replacement vessel was greater than 10 percent over the length, tonnage, or horsepower of the vessel on October 15, 2010. Alternative 2.4 stated that an AFA rebuilt or replacement vessel that is not subject to sideboards could not exceed the MLOA on any GOA LLP license assigned to the vessel on October 15, 2010.
Section 208(g)(2) of the amended AFA expressly gave the Council the authority to adopt conservation and management measures to ensure that the AFA amendments did not diminish the effectiveness of the fishery management plans for the Bering Sea or GOA. Alternatives 2.1, 2.2, 2.3, and 2.4 were the alternatives analyzed by the Council under section 208(g)(2).
As to which alternative achieves the objectives of the amended AFA, Alternatives 2, 2.1, 2.2, 2.3, and 2.4 all expand the ability of the owners of AFA vessels to rebuild or replace AFA vessels over the original AFA. However, Alternative 2 best achieves the objective
As to which alternative minimizes the adverse economic impact on small entities, the Analysis concluded that no AFA vessels are small entities. Therefore none of the alternatives directly regulates small entities and none of the alternatives minimize the adverse economic impacts on small entities.
But assuming for the purposes of analysis that the owners of AFA vessels are small entities, Alternative 2 is the alternative that minimizes the potential adverse economic impacts on the owners of AFA vessels. The reason is that Alternative 2 would allow the owners of AFA vessels to rebuild and replace their vessels without any restrictions on their ability to rebuild and replace vessels beyond the restrictions required by the AFA amendments. Alternative 2 allows the owners of AFA vessels to rebuild and replace their vessels if the vessel owners conclude that the improved safety and efficiency of the rebuilt or replacement vessel warrants the cost of rebuilding or replacing the vessel.
This proposed rule contains collection-of-information requirements subject to review and approval by the Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA). NMFS has submitted these requirements to OMB for approval under OMB Control Number 0648-0393. The public reporting burden for “American Fisheries Act (AFA) Permit: Rebuilt, Replacement, or Removed Vessel Application” is estimated to average 2 hours per response. This estimate includes the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection-of-information.
Public comment is sought regarding whether this proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the burden estimate; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the collection of information, including through the use of automated collection techniques or other forms of information technology. Send comments on these or any other aspects of the collection of information to NMFS at the
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. All currently approved NOAA collections of information may be viewed at:
Alaska, Fisheries, Reporting and recordkeeping requirements.
For the reasons set out in the preamble, 50 CFR part 679 is proposed to be amended as follows:
16 U.S.C. 773
(2) * * *
(vi) An AFA vessel is exempt from the MLOA on an LLP license with a Bering Sea area endorsement or an Aleutian Islands area endorsement when the vessel is used in the BSAI to harvest or process license limitation groundfish and the LLP license specifies an exemption from the MLOA restriction for the AFA vessel.
3. In § 679.4,
a. Remove paragraphs (a)(1)(iii)(F), (l)(4) introductory text, and (l)(8)(iv);
b. Redesignate paragraphs (l)(2)(iii) as (l)(2)(iv) and (l)(8)(v) as (l)(8)(iv);
c. Revise paragraphs (k)(1)(i), (k)(3)(i)(A), (l)(1)(ii)(B), (l)(3)(i)(A)(
d. Add paragraphs (k)(3)(i)(E), (l)(2)(iii), (l)(3)(i)(A)(
(k) * * *
(1) * * *
(i) In addition to the permit and licensing requirements of this part, and except as provided in paragraph (k)(2) of this section, each vessel within the GOA or the BSAI must have an LLP groundfish license on board at all times it is engaged in fishing activities defined in § 679.2 as directed fishing for license limitation groundfish. This groundfish license, issued by NMFS to a qualified person, authorizes a license holder to deploy a vessel to conduct directed fishing for license limitation groundfish only in accordance with the specific area and species endorsements, the vessel and gear designations, the MLOA specified on the license, and any exemption from the MLOA specified on the license.
(3) * * *
(i) * * *
(A)
(E)
(l) * * *
(1) * * *
(ii) * * *
(B)
(
(
(
(
(
(2) * * *
(iii)
(B) NMFS will issue an unlisted AFA catcher/processor permit to the owner of a catcher/processor that is a replacement vessel for a vessel that was designated on an unlisted AFA catcher/processor permit.
(3) * * *
(i) * * *
(A) * * *
(
(
(B) * * *
(
(
(C) * * *
(
(
(
(E) * * *
(
(4) * * *
(i) NMFS will issue to an owner of a mothership an AFA mothership permit if the mothership:
(A) Is one of the following (as listed in paragraphs 208(d)(1) through (3) of the AFA):
EXCELLENCE (USCG documentation number 967502);
GOLDEN ALASKA (USCG documentation number 651041); and
OCEAN PHOENIX (USCG documentation number 296779); or
(B) Is an AFA replacement vessel for a vessel that was designated on an AFA mothership permit.
(6) * * *
(ii) * * *
(C) * * *
(
(D)
(
(
(
(
(
(7)
(B) Except as provided in paragraph (l)(7)(i)(C) and paragraph (l)(7)(i)(D) of this section, the owner of an AFA rebuilt vessel will be subject to the same requirements that applied to the vessel before rebuilding and will be eligible to use the AFA rebuilt vessel in the same manner as the vessel before rebuilding.
(C) An AFA rebuilt vessel is exempt from the maximum length overall (MLOA) restriction on an LLP groundfish license with a Bering Sea area endorsement or an Aleutian Islands area endorsement when the AFA rebuilt vessel is conducting directed fishing for groundfish in the BSAI pursuant to that LLP groundfish license and the LLP groundfish license specifies the exemption.
(D) If an AFA rebuilt catcher vessel is equal to or greater than 125 ft (38.1 m) LOA, the AFA rebuilt catcher vessel will be subject to the catcher vessel exclusive fishing seasons for pollock in 50 CFR 679.23(i) and will not be exempt from 50 CFR 679.23(i) even if the vessel before rebuilding was less than 125 ft (38.1 m) LOA and was exempt from 50 CFR 679.23(i).
(ii)
(B) Upon approval of an application to replace an AFA vessel pursuant to paragraph (l)(7) of this section and except as provided in paragraph (l)(7)(ii)(C), paragraph (l)(7)(ii)(D), and paragraph (l)(7)(E) of this section, the owner of an AFA replacement vessel will be subject to the same requirements that applied to the replaced vessel and will be eligible to use the AFA replacement vessel in the same manner as the replaced vessel. If the AFA replacement vessel is not already designated on an AFA permit, the Regional Administrator will issue an AFA permit to the owner of the AFA replacement vessel. The AFA permit that designated the replaced, or former, AFA vessel will be revoked.
(C) An AFA replacement vessel is exempt from the maximum length overall (MLOA) restriction on an LLP groundfish license with a Bering Sea area endorsement or an Aleutian Islands area endorsement when the AFA replacement vessel is conducting directed fishing for groundfish in the BSAI pursuant to that LLP groundfish license and the LLP groundfish license specifies an exemption from the MLOA restriction for the AFA replacement vessel.
(D) If an AFA replacement catcher vessel is equal to or greater than 125 ft (38.1 m) LOA, the AFA replacement catcher vessel will be subject to the catcher vessel exclusive fishing seasons for pollock in 50 CFR 679.23(i) and will not be exempt from 50 CFR 679.23(i), even if the replaced vessel was less than 125 ft (38.1 m) LOA and was exempt from 50 CFR 679.23(i).
(E) An AFA replacement catcher vessel for an AFA catcher vessel will have the same sideboard exemptions, if any, as the replaced AFA catcher vessel, except that if the AFA replacement vessel was already designated on an AFA permit as exempt from sideboard limits, the AFA replacement vessel will maintain its exemption even if the replaced vessel was not exempt from sideboard limits.
(iii)
(B) The owner of the removed catcher vessel must direct NMFS to assign the non-CDQ inshore pollock catch history in the BSAI of the removed vessel to one or more catcher vessels in the inshore fishery cooperative to which the removed vessel belonged at the time of the application for removal.
(C) Except for the assignment of the pollock catch history of the removed catcher vessel in paragraph (l)(7)(iii)(B) of this section, all claims relating to the catch history of the removed catcher vessel, including any claims to an exemption from AFA sideboard limitations, will be permanently extinguished upon NMFS' approval of the application to remove the catcher vessel and the AFA permit that was held by the owner of the removed catcher vessel will be revoked.
(D) The catcher vessel or vessels that are assigned the catch history of the removed catcher vessel cannot be removed from the fishery cooperative to which the removed catcher vessel belonged for a period of one year from the date that NMFS assigned the catch history of the removed catcher vessel to that vessel or vessels.
(iv)
(v)
(8) * * *
(i)
(ii)
(iii)
(o) * * *
(4) * * *
(i) * * *
(D) The replacement vessel is not a vessel listed at section 208(e)(1) through (20) of the American Fisheries Act or permitted under paragraph (l)(2)(i) of this section; is not an AFA replacement vessel designated on a listed AFA catcher/processor permit under paragraph (l)(2)of this section; and is not an AFA catcher vessel permitted under paragraph (l)(3) of this section.
4. In § 679.7, revise paragraphs (i)(6), (k)(1)(ii), (k)(1)(iii), (k)(1)(iv), (k)(1)(v), (k)(1)(vi)(A) heading, (k)(1)(vi)(B) heading, (k)(1)(vii)(A) heading, (k)(1)(vii)(B) heading, and (k)(2)(ii) to read as follows:
(i) * * *
(6) Use a vessel to fish for LLP groundfish or crab species, or allow a vessel to be used to fish for LLP groundfish or crab species, that has an LOA that exceeds the MLOA specified on the license that authorizes fishing for LLP groundfish or crab species, except if the person is using the vessel to fish for LLP groundfish in the Bering Sea subarea or the Aleutian Islands subarea pursuant to an LLP license that specifies an exemption from the MLOA on the LLP license.
(k) * * *
(1) * * *
(ii)
(iii)
(iv)
(B) Use a listed AFA catcher/processor or a catcher/processor designated on a listed AFA catcher/processor permit as a stationary floating processor for Pacific cod in the GOA and a catcher/processor in the GOA during the same year.
(v)
(vi) * * *
(A)
(B)
(vii) * * *
(A)
(B)
(2) * * *
(ii)
(a) * * *
(2) * * *
(vi) * * *
(B) * * *
(
(
(a) * * *
(2)
(i) If NMFS approves the application of an owner of a catcher vessel that is a member of an inshore vessel cooperative to replace a catcher vessel pursuant to § 679.4(l)(7), NMFS will assign the AFA inshore pollock catch history of the replaced vessel to the replacement vessel.
(ii) If NMFS approves the application of an owner of a catcher vessel that is a member of an inshore vessel cooperative to remove a catcher vessel from the AFA directed pollock fishery pursuant to § 679.4(l)(7), NMFS will assign the AFA inshore pollock catch history of the removed vessel to one or more vessels in the inshore vessel cooperative to which the removed vessel belonged as required by § 679.4(l)(7); NMFS will not assign the catch history for any non-pollock species of the removed vessel to any other vessel, and NMFS will permanently extinguish any exemptions from sideboards that were specified on the AFA permit of the removed vessel.
(c)
(a)
(1)
(b) * * *
(2) * * *
(iii) An AFA rebuilt catcher vessel will have the same sideboard exemptions, if any, as the vessel before rebuilding, irrespective of the length of the AFA rebuilt catcher vessel.
(iv) An AFA replacement vessel for an AFA catcher vessel will have the same sideboard exemptions, if any, as the replaced AFA catcher vessel, irrespective of the length of the AFA replacement vessel, except that if the replacement vessel was already designated on an AFA permit as exempt from sideboard limits, the replacement vessel will maintain the exemption even if the replaced vessel was not exempt from sideboard limits.
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments regarding (a) whether the collection of information is necessary 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 burden 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 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 should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, 725 17th Street NW., Washington, DC 20502. Commenters are encouraged to submit their comments to OMB via email to:
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments regarding (a) whether the collection of information is necessary 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 burden 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 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.
Comments regarding this information collection received by July 18, 2014 will be considered. Written comments should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, 725 17th Street NW., Washington, DC 20502. Commenters are encouraged to submit their comments to OMB via email to:
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments regarding (a) whether the collection of information is necessary 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 burden 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 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 should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB),
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments regarding (a) whether the collection of information is necessary 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 burden 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 the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or
Comments regarding this information collection received by July 18, 2014 will be considered. Written comments should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, 725 17th Street NW., Washington, DC 20503. Commentors are encouraged to submit their comments to OMB via email to:
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act (FACA) that a planning meeting the Idaho Advisory Committee (Committee) to the Commission will be held on Thursday, July 10, 2014, at the Boise Public Library, 715 S. Capitol Boulevard, Boise, ID 83702. The meeting is scheduled to begin at 1:30 p.m. and adjourn at approximately 3:30 p.m. The purpose of the meeting is for the Committee to plan future project activity.
Members of the public are entitled to submit written comments. The comments must be received in the Western Regional Office of the Commission by August 10, 2014. The address is Western Regional Office, U.S. Commission on Civil Rights, 300 N. Los Angeles Street, Suite 2010, Los Angeles, CA 90012. Persons wishing to email their comments, or to present their comments verbally at the meeting, or who desire additional information should contact Angelica Trevino, Civil Rights Analyst, Western Regional Office, at (213) 894-3437, (or for hearing impaired TDD 913-551-1414), or by email to
Records generated from this meeting may be inspected and reproduced at the Western Regional Office, as they become available, both before and after the meeting. Persons interested in the work of this advisory committee are advised to go to the Commission's Web site,
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
Based on the management regime specified each year, designated regulatory areas in the commercial ocean salmon fishery off the coasts of Washington, Oregon, and California may be managed by numerical quotas. To accurately assess catches relative to quota attainment during the fishing season, catch data by regulatory areas must be collected in a timely manner. Requirements to land salmon within specific time frames and in specific areas may be implemented in the preseason regulations to aid in timely and accurate catch accounting for a regulatory area. State landing systems normally gather the data at the time of landing. If unsafe weather conditions or mechanical problems prevent compliance with landing requirements, fishermen need an alternative to allow for a safe response. Fishermen would be exempt from landing requirements if the appropriate notifications are made to provide the name of the vessel, the port where delivery will be made, the approximate amount of salmon (by species) on board, and the estimated time of arrival.
This information collection request may be viewed at
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
The king and Tanner crab fisheries in the exclusive economic zone of the Bering Sea and Aleutian Islands, Alaska, are managed under the Fishery Management Plan for Bering Sea and Aleutian Islands King and Tanner Crabs (FMP). The North Pacific Fishery Management Council prepared the FMP under the Magnuson-Stevens Fishery Conservation and Management Act as amended in 2006. National Marine Fisheries Service (NMFS) manages the crab fisheries in the waters off the coast of Alaska under the FMP. Regulations implementing the FMP and all amendments to the Crab Rationalization Program (CR Program) appear at 50 CFR part 680. Program details are found at:
The CR Program balances the interests of several groups who depend on the crab fisheries. The CR Program addresses conservation and management issues associated with the previous derby fishery, reduces bycatch and associated discard mortality, and increases the safety of crab fishermen by ending the race for fish. Share allocations to harvesters and processors, together with incentives to participate in fishery cooperatives, increases efficiencies, provides economic stability, and facilitates compensated reduction of excess capacities in the harvesting and processing sectors. Community interests are protected by Western Alaska Community Development Quota allocations and regional landing and processing requirements, as well as by several community protection measures.
The NMFS established the CR Program as a catch share program for nine crab fisheries in the Bering Sea and Aleutian Islands (BSAI), and assigned quota share (QS) to persons and processor quota share (PQS) to processors based on their historic participation in one or more of these nine crab fisheries during a specific period. The CR Program components include QS allocation, PQS allocation, individual fishing quota (IFQ) issuance, and individual processing quota (IPQ) issuance, quota transfers, use caps, crab harvesting cooperatives, protections for
This information collection request may be viewed at
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to
Department of Commerce.
Notice; Commerce/Department-24, BusinessUSA Intellectual Hosting Service Application and Satisfaction Survey Records.
The Department of Commerce (Commerce) publishes this notice to announce the effective date of a Privacy Act System of Records entitled Commerce/Department-24, BusinessUSA Intellectual Hosting Service Application and Satisfaction Survey Records. The notice of proposed amendment to this system of records was published in the
The system of records becomes effective on June 18, 2014.
For a copy of the system of records please mail requests to Efrain Gonzalez, Jr., BusinessUSA, U.S. Department of Commerce, Room 2830, 1401 Constitution Avenue NW., Washington, DC 20230.
Efrain Gonzalez, Jr., Chief Financial Officer/Chief Administrative Officer, BusinessUSA, 202-482-6407.
On May 13, 2014, the Department of Commerce published and requested comments on a proposed Privacy Act System of Records entitled Commerce/Department-24, BusinessUSA Intellectual Hosting Service Application and Satisfaction Survey Records (79 FR 92). No comments were received in response to the request for comments. By this notice, the Department is adopting the proposed system as final without changes effective June 18, 2014.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
On December 16, 2013, the Department of Commerce (the Department) published the preliminary results of the administrative review of the antidumping duty order on lightweight thermal paper from Germany.
Effective Date: June 18, 2014.
David Goldberger, AD/CVD Operations, Office II, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone (202) 482-4136.
Since the publication of the
The Department 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
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 2011-2012 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 Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (IA ACCESS). IA ACCESS is available to registered users at
As a result of this review, we determine that the following weighted-average dumping margin exists for the period November 1, 2011, through October 31, 2012.
We intend to disclose the calculations performed within five days of the date of publication of this notice to parties in this proceeding in accordance with 19 CFR 351.224(b).
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. Because we have calculated a zero margin for Koehler in the final results of this review, we will instruct CBP to liquidate the appropriate entries without regard to antidumping duties.
The Department clarified its “automatic assessment” regulation on May 6, 2003.
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) For Koehler, the calculated weighted-average margin rate is 0.00 percent and, accordingly, no cash deposit will be required; (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 could result in the Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
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 or 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. Exclusion of Certain Sales from Normal Value (NV) Calculations
2. Application of Adverse Facts Available (AFA) to Unreported U.S. Sales Quantity
3. Recalculation of Indirect Selling Expenses Incurred in the United States
4. Differential Pricing and Application of Average-to-Transaction Methodology
5. Ministerial Errors in Margin Calculation Program
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) is conducting an administrative review of the antidumping duty order on certain circular welded carbon steel pipes and tubes from Taiwan. The period of review (POR) is May 1, 2012, through April 30, 2013, and the review covers Shin Yang Steel Co., Ltd. (Shin Yang), a producer and exporter of subject merchandise. We preliminarily find that sales of the subject merchandise were not made at prices below normal value.
Steve Bezirganian or Robert James, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-1131 or (202) 482-0649, respectively.
The merchandise subject to the order is certain circular welded carbon steel pipes and tubes from Taiwan. The product is currently classified under the Harmonized Tariff Schedule of the United States (HTSUS) item numbers 7306.30.5025, 7306.30.5032,
For a full description of the methodology underlying our conclusions, please see the Preliminary Decision Memorandum.
The Department is conducting this review in accordance with section 751(a)(2) of the Tariff Act of 1930, as amended (the Act). Export Price is calculated in accordance with section 772 of the Act. Normal value is calculated in accordance with section 773 of the Act. For a full description of the methodology underlying our conclusions, please see the Preliminary Decision Memorandum.
As a result of this review, we preliminarily determine that a weighted-average dumping margin of 0.00 percent exists for Shin Yang for the POR.
The Department intends to disclose to interested parties the calculations performed in connection with these preliminary results within five days of the date of publication of this notice.
Pursuant to 19 CFR 351.310(c), interested parties who wish to request a hearing, or to participate if one is requested, must submit a written request to the Assistant Secretary for Import Administration, filed electronically via IA ACCESS within 30 days after the date of publication of this notice.
The Department will issue the final results of this administrative review, including the results of its analysis of the issues raised in any written briefs, not later than 120 days after the date of publication of this notice, pursuant to section 751(a)(3)(A) of the Act.
Upon completion of this administrative review, pursuant to 19 CFR 351.212(b), the Department will calculate importer-specific assessment rates for each respondent whose weighted-average dumping margin is not zero or
If the weighted-average dumping margin for Shin Yang is not zero or
The Department clarified its automatic assessment regulation on May 6, 2003.
The following cash deposit requirements for estimated antidumping duties will be effective upon publication of the notice of final results of administrative review for all shipments of certain circular welded carbon steel pipes and tubes from Taiwan entered, or withdrawn from warehouse, for consumption on or after the date of publication as provided by section 751(a)(2) of the Act: (1) The cash deposit for Shin Yang will be equal to the weighted-average dumping margin established in the final results of this administrative review; (2) for merchandise exported by manufacturers or exporters not covered in this review but covered in a previously completed segment of this proceeding, the cash deposit rate will continue to be the company-specific rate published for the most recently completed segment of this proceeding in which that manufacturer or exporter participated; (3) if the
This notice also serves as a preliminary reminder to importers of their responsibility under 19 CFR 351.402(f)(2) 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 could result in the Secretary's presumption that reimbursement of antidumping duties occurred and the subsequent assessment of double antidumping duties.
This notice also serves as a preliminary 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 the return or destruction of APO materials, or conversion to judicial protective order, will be requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act and 19 CFR 351.213(h)(1).
Notice.
The United States Patent and Trademark Office (USPTO), 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 the continuing information collection, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)).
Written comments must be submitted on or before August 18, 2014.
You may submit comments by any of the following methods:
•
•
•
Requests for additional information should be directed to the attention of LaRita Jones, Chief of the Workforce Employment Division, Office of Human Resources, United States Patent and Trademark Office (USPTO), P.O. Box 1450, Alexandria, VA 22313-1450; by telephone at 571-272-6196; or by email to
In the current employment environment, information technology professionals and engineering graduates are in great demand. The USPTO is in direct competition with private industry for the same caliber of candidates with the requisite knowledge and skills to perform patent examination work. The use of automated online systems allows the USPTO to remain competitive, meet hiring goals, and fulfill the agency's Congressional commitment to reduce the pendency rate for the examination of patent applications. The information supplied by an applicant seeking a patent examiner position with the USPTO assists the Human Resources Specialists and hiring managers in determining whether an applicant possesses the basic qualification requirements for the patent examiner position.
The Monster Hiring Management (MHM) system is an automated online system that allows the USPTO to rapidly review applications for employment of entry-level patent examiners. The Office of Human Resources (OHR) can use the system to rapidly review applications for employment and take the necessary administrative action to support the hiring process.
The online application creates an electronic real-time candidate inventory that allows the USPTO to review applications from potential applicants almost instantaneously. Given the immediate hiring need of the Patent Examining Corps, time consumed in the mail distribution system or paper review of applications delays the decision-making process by several weeks. The MHM system results in increased speed and accuracy in the employment process, in addition to streamlining labor and reducing costs.
The use of the MHM online application fully complies with 5 U.S.C. § 2301, which requires adequate public notice to assure open competition by guaranteeing that necessary employment information will be accessible and available to the public on inquiry. It is also fully compliant with Section 508 (29 U.S.C. § 794(d)), which requires agencies to provide disabled employees and members of the public access to information that is comparable to the access available to others.
With the use of MHM, the application information is collected electronically from the applicant. The USAJobs.gov Web site provides the online job announcement that links the applicant to the application and the MHM system. The application is completed online and then transmitted to the USPTO via the Internet.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record.
The USPTO is soliciting public comments to: (a) 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; (b) 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; (c) Enhance the quality, utility, and clarity of the information to be collected; and (d) 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 submission of responses.
Corporation for National and Community Service (CNCS).
Guidance for CNCS Notices, with request for comments.
CNCS is submitting the below information for future CNCS
Comments must be submitted July 18, 2014.
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 CNCS, by any of the following two methods within 30 days from the date of publication in the
(1) By fax to: 202-395-6974, Attention: Ms. Sharon Mar, OMB Desk Officer for CNCS; and
(2) Electronically by email to:
To request additional information, please contact Amy Borgstrom, Associate Director of Policy, at 202-606-6930 or email to
The Agency will only submit a collection for approval under this generic clearance if it meets the following conditions:
• The collections are voluntary;
• The collections are low-burden for respondents (based on considerations of total burden hours, total number of respondents, or burden-hours per respondent) and are low-cost for both the respondents and the Federal Government;
• The collections are non-controversial and do not raise issues of concern to other Federal agencies;
• Any collection is targeted to the solicitation of opinions from respondents who have experience with the program or may have experience with the program in the near future;
• Personally identifiable information (PII) is collected only to the extent necessary and is not retained;
• Information gathered will be used only internally for general service improvement and program management purposes and is not intended for release outside of the agency;
• Information gathered will not be used for the purpose of substantially informing influential policy decisions; and
• Information gathered will yield qualitative information; the collections will not be designed or expected to yield statistically reliable results or used as though the results are generalizable to the population of study.
Feedback collected under this generic clearance provides useful information, but it does not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior to fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
As a general matter, information collections will not result in any new system of records containing privacy information and will not ask questions of a sensitive nature, such as sexual behavior and attitudes, religious beliefs, and other matters that are commonly considered private.
No comments were received in response to the 60-day notice published in the
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 Office of Management and Budget Control Number.
Corporation for National and Community Service (CNCS).
Guidance for CNCS Notices, with request for comments.
CNCS is submitting the below information for future CNCS
Comments must be submitted July 18, 2014.
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 CNCS, by any of the following two methods within 30 days from the date of publication in the
(1) By fax to: 202-395-6974, Attention: Ms. Sharon Mar, OMB Desk Officer for CNCS; and
(2) Electronically by email to:
To request additional information, please contact Amy Borgstrom, Associate Director of Policy, at 202-606-6930 or email to
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
No comments were received in response to the 60-day notice published in the
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 Office of Management and Budget Control Number.
DoD.
Renewal of Federal Advisory Committee.
The Department of Defense is publishing this notice to announce that it is renewing the charter for the Missouri River (North Dakota) Task Force (“the Task Force”).
Jim Freeman, Advisory Committee Management Officer for the Department of Defense, 703-692-5952.
This committee's charter is being renewed under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C. Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b) (“the Sunshine Act”), and 41 CFR 102-3.50(d).
The Task Force is a nondiscretionary Federal advisory committee that shall provide independent advice and recommendations to the Secretary of the Army on plans and projects to reduce siltation of the Missouri River in the State of North Dakota and to meet the objectives of the Pick-Sloan Program. Specifically, the Task Force shall:
a. Prepare and approve, by a majority of the members, a plan for the use of the funds made available under the Missouri River Act, to promote conservation practices in the Missouri River watershed, control and remove the sediment from the Missouri River, protect recreation on the Missouri River from sedimentation, protect Indian and non-Indian historical and cultural sites along the Missouri River from erosion, and control erosion along the Missouri River;
b. Develop and recommend to the Secretary of the Army for implementation critical restoration projects meeting the goals of the plan; and
c. Determine if these projects primarily benefit the Federal Government.
The Task Force may, on an annual basis, revise the plan and shall provide the public with the opportunity to review and comment on any proposed revision.
The Task Force shall report to the Secretary of the Army and the U.S. Army Corps of Engineers.
The Secretary of the Army may act upon the Task Force's advice and recommendations.
The Department of Defense (DoD), through the Secretary of the Army, the Assistant Secretary of the Army for Civil Works, and the U.S. Army Corps of Engineers, shall provide support, as deemed necessary, for the performance of the Task Force's functions, and shall ensure compliance with the requirements of the FACA, the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended) (“the Sunshine Act”), governing Federal statutes and regulations, and established DoD policies and procedures.
Pursuant to Section 704 and 705 of the Missouri River Protection and Improvement Act of 2000 (“the Missouri River Act”) (Title VII of Pub. L. 106-541, the Water Resources Development Act of 2000), the Task Force shall be composed of not more than 20 members. Specifically, the Task Force membership shall be composed of:
a. The Secretary of the Army or designee, who shall serve as the Chair;
b. The Secretary of Agriculture or designee;
c. The Secretary of Energy or designee;
d. The Secretary of the Interior or designee; and
e. The Trust, which is composed of 16 members to be appointed by the Secretary of the Army, including:
i. Twelve members recommended by the Governor of North Dakota that represent, equally, the various interests of the public and include representatives of:
a. the North Dakota Department of Health,
b. the North Dakota Department of Parks and Recreation,
c. the North Dakota Department of Game and Fish,
d. the North Dakota State Water Commission,
e. the North Dakota Indian Affairs Commission,
f. agricultural groups,
g. environmental or conservation organizations,
h. the hydroelectric power industry,
i. recreations user groups,
j. local governments,
k. and other appropriate interests.
ii. Four members representing each of the four Indian tribes in the State of North Dakota. The members of the Trust shall be appointed by the Secretary of the Army as representative members to the Task Force, pursuant to 41 CFR 102-3.130(a). Those individuals who are full-time or permanent part-time Federal employees shall be appointed regular government employee (RGE) members, pursuant to 41 CFR 102-3.130(a).
All representative members of the Trust shall be appointed for a two-year term of service; and no member, unless authorized by the Secretary of Defense upon request of the Secretary of the Army, may serve more than two consecutive terms of service. In addition, all Task Force members shall, with the exception of reimbursement of official Task Force-related travel and per diem, serve without compensation.
The Department, when necessary and consistent with the Task Force's mission and DoD policies and procedures, may establish subcommittees, task forces, or working groups to support the Task Force. Establishment of subcommittees will be based upon a written determination, to include terms of reference, by the Secretary of Defense, the Deputy Secretary of Defense, or the Secretary of the Army, as the Task Force's Sponsor.
Such subcommittees shall not work independently of the chartered Task Force and shall report all of their recommendations and advice solely to the Task Force for full and open deliberation and discussion. Subcommittees, task forces, or working groups have no authority to make decisions and recommendations, verbally or in writing, on behalf of the Task Force. No subcommittee or any of its members can update or report, verbally or in writing, on behalf of the Task Force, directly to the DoD or any Federal officers or employees.
The Secretary of Defense or the Deputy Secretary of Defense may approve the appointment of subcommittee members for a two-year term of service with annual renewals; however, no member, unless authorized by the Secretary of Defense, may serve more than two consecutive terms of service. These individuals may come from the Task Force or may be new nominees, as recommended by the
Subcommittee members, if not full-time or permanent part-time Federal employees, shall be appointed as experts or consultants, pursuant to 5 U.S.C. 3109, to serve as special government employee members. Those individuals who are full-time or permanent part-time Federal employees will be appointed, pursuant to 41 CFR 102-3.130(a), to serve as RGE members.
With the exception of reimbursement for official Task Force-related travel and per diem, subcommittee members shall serve without compensation.
All subcommittees operate under the provisions of FACA, the Sunshine Act, governing Federal statutes and regulations, and established DoD policies and procedures.
The Designated Federal Officer (DFO), pursuant to DoD policy, shall be a full-time or permanent part-time DoD employee, and shall be appointed in accordance with established DoD policies and procedures.
In addition, the DFO is required to be in attendance at all meetings of the Task Force and any subcommittees, for the entire duration of each and every meeting; however, in the absence of the DFO, a properly approved Alternate DFO, duly appointed to the Task Force according to established DoD policies and procedures, shall attend the entire duration of all meetings of the Task Force or its subcommittees.
The DFO or the Alternate DFO, shall call all meetings of the Task Force and its subcommittees; prepare and approve all meeting agendas; and adjourn any meeting when the DFO, or the Alternate DFO, determines adjournment to be in the public interest or required by governing regulations or DoD policies and procedures.
Pursuant to 41 CFR 102-3.105(j) and 102-3.140, the public or interested organizations may submit written statements to Missouri River (North Dakota) Task Force membership about the Task Force's mission and functions. Written statements may be submitted at any time or in response to the stated agenda of planned meeting of Missouri River (North Dakota) Task Force.
All written statements shall be submitted to the DFO for the Missouri River (North Dakota) Task Force, and this individual will ensure that the written statements are provided to the membership for their consideration. Contact information for the Missouri River (North Dakota) Task Force DFO can be obtained from the GSA's FACA Database—
Department of Defense.
Notice of Demonstration.
This notice is to advise interested parties of a Military Health System (MHS) demonstration project under the authority of Title 10, United States Code, Section 1092, entitled Defense Health Agency (DHA) Evaluation of Non-United States Food and Drug Administration (FDA) Approved Laboratory Developed Tests (LDTs) Demonstration Project. The demonstration project is intended to further evaluate whether it is feasible for the Department of Defense (DoD) to review LDTs not yet examined by the FDA to determine if they meet TRICARE's requirements for safety and effectiveness according to the hierarchy of reliable evidence (32 CFR 199.4(g)(15)(i)(C) and 32 CFR 199.2(b)), or TRICARE's rare disease policy (32 CFR 199.4(g)(15)(ii)) in the case of LDTs used in the diagnosis or medical management of a rare disease (32 CFR 199.2(b)), and allow those that do to be covered as a benefit under the TRICARE Program. The demonstration project will evaluate feasible alternatives to support modifications to 32 CFR 199.4(g)(15)(i)(A) to allow coverage for non-FDA approved LDTs that otherwise meet the TRICARE requirements for safety and effectiveness. The Department currently has an ongoing demonstration project to test this same provision for LDTs with a Center for Medicare and Medicaid Services (CMS) national or local coverage determination that were submitted by laboratories for consideration for coverage under TRICARE. However, this new demonstration is being conducted in order to be able to evaluate the feasibility of establishing a cost-effective and efficient way to review an expanded pool of non-FDA approved LDTs prioritized based on their potential high utilization and clinical utility within the TRICARE population. This new demonstration project will also extend coverage for prenatal and preconception cystic fibrosis carrier screening, when provided in accordance with the American College of Obstetricians and Gynecologists guidelines in order to allow DoD to establish whether there is a benefit to offering such testing to TRICARE beneficiaries.
This demonstration will be effective July 18, 2014. This demonstration will remain in effect for three years.
Defense Health Agency, Attn: Clinical Support Division, 7700 Arlington Blvd., Falls Church, VA 22040.
Jim Black, Clinical Support Division, Defense Health Agency, Telephone (703) 681-0068.
According to 32 CFR 199.4(g)(15)(i)(A), TRICARE may not cost-share medical devices including LDTs if the tests are non-FDA cleared or approved; that is, they have not received FDA medical device 510(k) clearance or premarket approval. For purposes of this demonstration, LDTs that are not FDA cleared or approved will hereinafter be referred to as non-FDA approved for brevity purposes. Under the current regulation cited above, LDTs that have been identified as non-FDA approved are summarily denied.
An LDT is an in vitro diagnostic (IVD) that is designed, manufactured, and used within a single laboratory. In the past, these tests were relatively simple tests used within a single laboratory, usually at a local large hospital or academic medical center, to diagnose rare diseases or for other uses to meet the needs of a local patient population. The FDA has exercised enforcement discretion in that the agency has generally not enforced applicable provisions under the Federal Food, Drug, and Cosmetic Act (FFDCA) and its regulations with respect to LDTs.
The 1976 Medical Device Amendments modified the FFDCA to provide for a comprehensive system for the regulation of medical devices. The term “device” is defined broadly in 21 U.S.C. 321(h) to include: “an
FDA regulations in 21 CFR 809.3 define “in vitro diagnostic products” as: “those reagents, instruments, and systems intended for use in diagnosis of disease or other conditions, including a determination of the state of health, in order to cure, mitigate, treat, or prevent disease or its sequelae. Such products are intended for use in the collection, preparation, and examination of specimens taken from the human body.” As explained above, LDTs are a subset of IVDs. The FDA has stated that clinical laboratories that develop LDTs are acting as manufacturers of medical devices and are subject to FDA jurisdiction under the FFDCA. As noted, the FDA has chosen to exercise its “enforcement discretion” over many LDTs and these tests are routinely sold without FDA approval.
The Analyte Specific Reagents (ASRs) rule was published in 1997 (21 CFR 864.4020), classifying most ASRs (ASRs are considered to be the “active ingredients” of tests) as Class I devices. The intent was to ensure the quality of the test components and to continue enforcement discretion for LDTs.
During the 2000s, LDTs became more complex at an increasingly fast pace. In response, the FDA issued draft guidance in 2007 relating to In Vitro Diagnostic Multivariate Index Assays, a particularly complex category of tests. Final guidance has yet to be published. In July 2010, the FDA held a public meeting to discuss the agency's oversight of LDTs. In announcing the public meeting, the FDA explained:
At the same time as LDTs are becoming more complex, diagnostic tests are playing an increasingly important role in clinical decision making and disease management, particularly in the context of personalized medicine. However, LDTs that have not been properly validated for their intended use put patients at risk. Risks include missed diagnosis, wrong diagnosis, and failure to receive appropriate treatment. . . . [and] some diagnostics critical for patient care may not be developed in a manner that provides a reasonable assurance of safety and effectiveness.
Laboratories are assessed and accredited under minimum quality standards set by CMS under the Clinical Laboratory Improvement Amendments (CLIA) of 1988. CMS regulates laboratories that use LDTs as well as FDA approved tests. Laboratories performing moderate or high complexity tests are subject to specific regulatory standards governing certification, personnel, proficiency testing, patient test management, quality assurance, quality control, and inspections. CLIA certification and periodic inspections evaluate whether the laboratory has determined the analytical validity of the tests they offer, including LDTs. Analytical validity refers to how well a test performs in the laboratory; that is, how well the test measures the properties or characteristics it is intended to measure. CLIA certification does not, however, assure a device is safe and effective for its intended use, or impose any type of postmarket surveillance or adverse event reporting requirements.
On December 27, 2011, the DoD published a notice in the
In general, the TRICARE program has been, and continues to be, a benefit program based on medical necessity. The current TRICARE maternity benefit is limited to coverage of medically necessary services and supplies associated with maternity care in accordance with 32 CFR 199.4(e)(16). Further, TRICARE covers genetic testing that is medically necessary and appropriate in the diagnosis and/or treatment of a disease and when the results of the test will influence the medical management of the individual or pregnancy. Routine genetic testing, including carrier screening, that does not influence a beneficiary's medical management is specifically excluded from TRICARE coverage.
For cystic fibrosis (CF) testing in particular, TRICARE covers CF testing when performed as part of a newborn screening panel as part of well-child care. TRICARE will also cover diagnostic genetic testing for CF when it is performed on individuals to confirm a clinical diagnosis that is already suspected. TRICARE does not, however, cover pre-conception CF carrier screening for couples planning a pregnancy, pre-implantation CF screening of embryos, or prenatal CF screening of pregnant women since the results do not assist in the medical management of the patient or pregnancy. Awareness that a fetus is at increased risk of having CF, in and of itself, does not usually change the management of labor, delivery, and the neonatal period. Additionally, newborn screening panels, which are performed shortly after birth, include tests for a number of conditions including CF, and are a TRICARE covered benefit.
Notwithstanding current TRICARE benefit limitations, the Department of Defense is aware of the widespread acceptance the American College of Obstetricians and Gynecologists (ACOG) guidelines of carrier screening for CF have received. Carrier screening for CF has been widely recognized and commonly provided as part of routine obstetric practice.
Consequently, the DoD will initiate a new and expanded demonstration project to test whether non-FDA approved LDTs meet TRICARE's requirements for safety and effectiveness in order to permit TRICARE cost-sharing. The demonstration project will be effective 30 days after publication in the
Non-FDA approved LDTs will be prioritized and reviewed for analytical validity, clinical validity, and clinical utility. LDT reviews will be based on the TRICARE hierarchy of reliable evidence, as defined below, to determine whether the specific test is proven safe and effective for TRICARE cost-sharing purposes.
Reliable evidence is defined in 32 CFR 199.2(b) and includes: “(i) Well-controlled studies of clinically meaningful endpoints, published in refereed medical literature; (ii) Published formal technology assessments; (iii) The published reports of national professional medical associations; (iv) Published national medical policy organization positions; and (v) The published reports of national expert opinion organizations.” The definition goes on to state, “The hierarchy of reliable evidence of proven medical effectiveness, established by (i) through (v) of this paragraph, is the order of the relative weight to be given to any particular source. With respect to clinical studies, only those reports and articles containing scientifically valid data and published in the refereed medical and scientific literature shall be considered as meeting the requirements of reliable evidence. Specifically not included in the meaning of reliable evidence are reports, articles, or statements by providers or groups of providers containing only abstracts, anecdotal evidence, or personal professional opinions. Also not included in the meaning of reliable evidence is the fact that a provider or a number of providers have elected to adopt a drug, device, or medical treatment or procedure as their personal treatment or procedure of choice or standard of practice.”
There may also be non-FDA approved LDTs reviewed under the new demonstration project for use in the diagnosis or medical management of a rare disease. In accordance with 32 CFR 199.2(b), TRICARE defines a rare disease as any disease or condition that has a prevalence of less than 200,000 persons in the United States. Due to the rare nature of the condition and lack of clinical research, the hierarchy of reliable evidence as described previously may not be met. In accordance with 32 CFR 199.4(g)(15)(ii), benefits for rare diseases are reviewed on a case-by-case basis. In reviewing proposed benefits for rare diseases under the new demonstration, consistent with TRICARE's rare disease policy, a proposed LDT for a rare disease may be reviewed for analytical validity, clinical validity, and clinical utility from any or all of the following sources to determine if the proposed LDT for a rare disease is considered safe and effective for TRICARE cost-sharing purposes: (i) Trials published in refereed medical literature; (ii) Formal technology assessments; (iii) National medical policy organization positions; (iv) National professional associations; and, (v) National expert opinion organizations.
The DoD's Laboratory Joint Working Group (LJWG) will be responsible for prioritizing and reviewing the non-FDA approved LDTs for the new demonstration. Representatives are appointed by the Assistant Secretary of Defense (Health Affairs) and are comprised of government clinical and policy professionals (DoD employees and Active Duty Service Members). Reliable evidence reviews may also be performed by a third party with the appropriate expertise and recommendations provided to the LJWG.
The LJWG will prioritize the LDTs based on their potential high utilization and high clinical utility within the TRICARE population based on existing direct and purchased care data. LDTs used for non-covered conditions or tests related to unproven treatments will not be eligible for coverage and thus will not be reviewed under the new demonstration or recommended by the LJWG. Selected LDTs will be evaluated using the hierarchy of reliable evidence or rare disease policy as outlined above. By majority vote, the LJWG will recommend approval or disapproval to the Director, DHA, or designee. Approved LDTs will be available for cost-sharing under the new demonstration.
Non-FDA approved LDTs determined to meet TRICARE's requirements for safety and effectiveness according to the hierarchy of reliable evidence or rare disease policy, and otherwise meet TRICARE criteria for coverage, will be recommended to the Director, DHA, or designee, for decision for approval for cost-sharing during the new demonstration period. The effective date for coverage of specific LDTs approved under the new demonstration project will be the later of: (1) January 1, 2013; or (2) the date on which there is sufficient reliable evidence to determine that the specific LDT is proven safe and effective for TRICARE cost-sharing purposes. LDTs that have been approved by the Director, DHA, or designee, under the new demonstration, as well as LDTs that have been evaluated under the new demonstration and found to lack sufficient reliable evidence of safety and efficacy and thus remain excluded from coverage, will be appropriately documented in the TRICARE Operations Manual (TOM) following existing processes. Additional information on payment methodologies will be included in the operational procedures for the new demonstration and will be published in the TOM found at
Decisions regarding which LDTs are reviewed under the new demonstration, including the priority of review, are not appealable. Additionally, in order to dedicate maximum resources to the review of LDTs under the new demonstration, no formal appeal rights will be extended for tests that are reviewed under the new demonstration and found to lack sufficient reliable evidence of safety and efficacy. Should the new demonstration project be deemed successful and permanent regulatory authority enacted, appeal rights will be available as provided in 32 CFR 199.10.
This new demonstration project will also extend coverage for prenatal and preconception CF carrier screening, when provided in accordance with the ACOG guidelines. This demonstration project will allow DoD to establish whether there is a benefit to offering such testing for purposes of determining whether to permanently establish coverage as part of the family planning genetic testing benefit at 32 CFR 199.4(e)(3)(ii), the maternity benefit at 32 CFR 199.4(e)(16), or otherwise as a special benefit. By extending coverage for CF carrier screening in accordance with ACOG guidelines under this demonstration project DoD will be able to gather the necessary data to evaluate whether there is a benefit to offering such screening, including evaluating the impact on follow-on care that a patient is given based on testing results and any other identified benefits of the testing. The Director, DHA (or designee) shall issue guidelines for collection of data involving individual cases of CF carrier screening covered under this demonstration as necessary for evaluation of the benefits resulting from
The new demonstration is effective 30 days after publication in the
An annual evaluation of the new demonstration will be conducted to determine how many TRICARE approved LDTs were provided to beneficiaries across all TRICARE Regions. The evaluation will also include a review of the LDT examination and recommendation process to assess feasibility, resource requirements, and cost-effectiveness of DHA establishing an internal safety and efficacy review process for these devices for TRICARE cost-sharing purposes. These results of the evaluation will provide an evaluation of the potential improvement of the quality of healthcare services for beneficiaries who would not otherwise have access to these safe and effective tests. Based on the results of the demonstration evaluation, a recommendation will be made on whether to modify 32 CFR 199.4(g)(15)(i)(A) to remove the restriction for non-FDA approved LDTs and permit TRICARE cost-sharing of LDTs that are found to otherwise meet TRICARE requirements for safety and effectiveness. The Department of Defense will also conduct a cost benefit analysis of providing CF carrier screening in accordance with ACOG guidelines to the TRICARE beneficiary population for purposes of determining whether to permanently establish coverage.
Office of Special Education and Rehabilitative Services (OSERS), 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 August 18, 2014.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
For specific questions related to collection activities, please contact Meredith Miceli, 202-245-6028.
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.
Institute of Education Sciences/National Center for Education Sciences Statistics (IES), 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 August 18, 2014.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
For specific questions related to collection activities, please contact Elizabeth Warner, 202-208-7169.
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 Educations and Rehabilitative Services (OSERS), 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 August 18, 2014.
Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at
For specific questions related to collection activities, please contact Meredith Miceli, 202-245-6028.
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
The following notice of meeting is published pursuant to section 3(a) of the government in the Sunshine Act (Pub. L. 94-409), 5 U.S.C. 552b:
Federal Energy Regulatory Commission.
June 19, 2014, 10:00 a.m.
Room 2C, 888 First Street NE., Washington, DC 20426.
Open.
Agenda
* NOTE—Items listed on the agenda may be deleted without further notice.
Kimberly D. Bose, Secretary, Telephone (202) 502-8400.
For a recorded message listing items struck from or added to the meeting, call (202) 502-8627.
This is a list of matters to be considered by the Commission. It does not include a listing of all documents relevant to the items on the agenda. All public documents, however, may be viewed on line at the Commission's Web site at
A free webcast of this event is available through
Immediately following the conclusion of the Commission Meeting, a press briefing will be held in the Commission Meeting Room. Members of the public may view this briefing in the designated overflow room. This statement is intended to notify the public that the press briefings that follow Commission meetings may now be viewed remotely at Commission headquarters, but will not be telecast through the Capitol Connection service.
Environmental Protection Agency.
Notice.
The Environmental Protection Agency (EPA) is planning to submit an information collection request (ICR), 2015 Hazardous Waste Report, Notification of Regulated Waste Activity, and Part A Hazardous Waste Permit Application and Modification (EPA ICR No. 0976. 17, OMB Control No. 2050-0024) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Comments must be submitted on or before August 18, 2014.
Submit your comments, referencing by Docket ID No. EPA-HQ-RCRA-2014-0296, online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Peggy Vyas, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: 703-308-5477; fax number: 703-308-8433; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Pursuant to section 3506(c)(2)(A) of the PRA, EPA is soliciting comments and information to enable it to: (i) 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; (ii) 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; (iii) enhance the quality, utility, and clarity of the information to be collected; and (iv) 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 submission of responses. EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval. At that time, EPA will issue another
Section 3010 of RCRA requires any person who generates or transports regulated waste or who owns or operates a facility for the treatment, storage, or disposal of regulated waste to notify the EPA of their activities, including the location and general description of activities and the regulated wastes handled. The entity is then issued an EPA Identification number. Entities use the Notification Form (EPA Form 8700-12) to notify EPA of their hazardous waste activities. This form is also known as the “Notification” form.
Section 3005 of RCRA requires TSDFs to obtain a permit. To obtain the permit, the TSDF must submit an application describing the facility's operation. The RCRA Hazardous Waste Part A Permit Application form (EPA Form 8700-23) defines the processes to be used for treatment, storage, and disposal of hazardous wastes; the design capacity of such processes; and the specific hazardous wastes to be handled at the facility. This form is also known as the “Part A” form.
Environmental Protection Agency.
Notice of the designation of four new equivalent methods for monitoring ambient air quality.
Notice is hereby given that the Environmental Protection Agency (EPA) has designated, in accordance with 40 CFR part 53, four new equivalent methods: One for measuring concentrations of nitrogen dioxide (NO
Robert Vanderpool, Human Exposure and Atmospheric Sciences Division (MD-D205-03), National Exposure Research Laboratory, U.S. EPA, Research Triangle Park, North Carolina 27711. Email:
In accordance with regulations at 40 CFR part 53, the EPA evaluates various methods for monitoring the concentrations of those ambient air pollutants for which EPA has established National Ambient Air Quality Standards (NAAQSs) as set forth in 40 CFR part 50. Monitoring methods that are determined to meet specific requirements for adequacy are designated by the EPA as either reference methods or equivalent methods (as applicable), thereby permitting their use under 40 CFR part 58 by States and other agencies for determining compliance with the NAAQSs.
The EPA hereby announces the designation of one new equivalent method for measuring nitrogen dioxide (NO
The new equivalent method for NO
EQNA-0514-212, “Teledyne Advanced Pollution Instrumentation, Model T500U cavity attenuated phase shift spectroscopy Nitrogen Dioxide Analyzer”, operated on any full scale range between 0-50 ppb and 0-1000 ppb, with any range mode (Single, Dual, or AutoRange), with a sample particulate filter, at any operating temperature from 5 °C to 40 °C, with the following software setting: Temperature and Pressure compensation ON; in accordance with the associated instrument manual, and with or without any of the following options: Zero/Span valves, internal Zero/Span permeation oven (IZS), external communication and data monitoring interfaces.
One new O
EQOA-0514-214, “Teledyne Advanced Pollution Instrumentation, Model T204 NO
The application for the equivalent method determination for the NO
A second O
EQOA-0514-215, “2B Technologies Model 211 Scrubberless Ozone Monitor,” operated in a range of 0-0.5 ppm in an environment of 20-30 °C, with temperature and pressure compensation, internal DewLine for humidity control, gas phase titration of ozone for interference-free measurements, using a 1 minute average, with a 110-220V AC power adapter or a 12V DC source, 8.0 to 12.0 watt power consumption, operated according to the Model 211 Scrubberless Ozone Monitor Operation Manual with either an external nitric oxide source or internal photolytic generator for production of NO scrubber gas from nitrous oxide, and with or without the following: Cigarette lighter adapter or a 12V DC battery for portable operation, external PTFE inlet filter and holder,
The application for an equivalent method determination for this candidate method was received by the EPA on January 14, 2014. The analyzer models are commercially available from the applicant, 2B Technology, Inc., 2100 Central Ave., Suite 105, Boulder, CO 80303.
The new equivalent method for Pb is a manual method that uses the sampling procedure specified in the Reference Method for the Determination of Lead in Suspended Particulate Matter Collected From Ambient Air (High-Volume Sampler), 40 CFR Part 50, Appendix G, with a different extraction and analytical procedure. The method is identified as follows:
EQL-0514-213 “
The application for equivalent method determination for this Pb method was submitted by South Coast Air Quality Management District, 21865 Copley Drive, Diamond Bar, CA 91765-4182 and was received by the EPA's Office of Research and Development on May 18, 2012. The method descriptions will be available at
Test monitors representative of these methods have been tested in accordance with the applicable test procedures specified in 40 CFR part 53, as amended on August 31, 2011. After reviewing the results of those tests and other information submitted in the applications, EPA has determined, in accordance with Part 53, that these methods should be designated as equivalent methods.
As designated equivalent methods, these methods are acceptable for use by states and other air monitoring agencies under the requirements of 40 CFR part 58, Ambient Air Quality Surveillance. For such purposes, the methods must be used in strict accordance with the operation or instruction manuals associated with the methods and subject to any specifications and limitations (e.g., configuration or operational settings) specified in the applicable designated descriptions (see the identification of the methods above).
Use of the methods also should be in general accordance with the guidance and recommendations of applicable sections of the “Quality Assurance Handbook for Air Pollution Measurement Systems, Volume I,” EPA/600/R-94/038a and “Quality Assurance Handbook for Air Pollution Measurement Systems, Volume II, Ambient Air Quality Monitoring Program” EPA-454/B-08-003, December, 2008. Provisions concerning modification of such methods by users are specified under Section 2.8 (Modifications of Methods by Users) of Appendix C to 40 CFR part 58.
Consistent or repeated noncompliance should be reported to: Director, Human Exposure and Atmospheric Sciences Division (MD-E205-01), National Exposure Research Laboratory, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711.
Designation of these equivalent methods is intended to assist the States in establishing and operating their air quality surveillance systems under 40 CFR part 58. Questions concerning the commercial availability or technical aspects of the methods should be directed to the applicant.
Office of External Affairs and Environmental Education, Environmental Protection Agency.
Notice.
The National Environmental Education and Training Foundation (doing business as The National Environmental Education Foundation or NEEF) was created by Section 10 of Public Law #101-619, the National Environmental Education Act of 1990. It is a private 501(c)(3) non-profit organization established to promote and support education and training as necessary tools to further environmental protection and sustainable, environmentally sound development. It provides the common ground upon which leaders from business and industry, all levels of government, public interest groups, and others can work cooperatively to expand the reach of environmental education and training programs beyond the traditional classroom. The Foundation promotes innovative environmental education and training programs such as environmental education for medical healthcare providers and broadcast meteorologists; it also develops partnerships with government and other organizations to administer projects that promote the development of an environmentally literal public. The Administrator of the U.S. Environmental Protection Agency, as required by the terms of the Act, announces the following appointment to the National Environmental Education Foundation Board of Directors. The appointee is David M. Kiser, Ph.D., Vice President, Environment, Health, Safety and Sustainability, International Paper.
For information regarding this Notice of Appointment, please contact Mr. Brian Bond, Senior Advisor to the Administrator for Public Engagement, U.S. EPA 1200 Pennsylvania Ave. NW., Washington, DC 20460. General information concerning NEEF can be found on their Web site at:
This appointee will join the current Board members which include:
○ Decker Anstrom (NEEF Chairman) Former U.S. Ambassador, Retired Chairman, The Weather Channel Companies.
○ Trish Silber (NEEF Vice Chair) President, Aliniad Consulting Partners, Inc.
○ Kenneth Strassner (NEEF Treasurer) Strassner Consulting, LLC.
○ Diane Wood (NEEF Secretary) President, National Environmental Education Foundation.
○ Carlos Alcazar, Founder and Chairman, Culture ONE World.
○ Megan Reilly Cayten, Co-Founder and Chief Executive Officer, Catrinka, LLC.
○ Philippe Cousteau, Co-Founder and CEO, EarthEcho International.
○ Wonya Lucas, President, Lucas Strategic Consulting.
○ Shannon Schuyler, Principal, Corporate Responsibility Leader, PricewaterhouseCoopers (PwC).
○ Bradley Smith, Ph.D., Emeritus Dean, Huxley College of the Environment, Western Washington University.
○ Jacqueline M. Thomas, Vice President of Corporate Responsibility, Toyota Motor Sales USA Inc.
The Foundation is a charitable and nonprofit corporation whose income is exempt from tax, and donations to which are tax deductible to the same extent as those organizations listed pursuant to section 501(c) of the Internal Revenue Code of 1986. The Foundation is not an agency or establishment of the United States. The purposes of the Foundation are—
(A) Subject to the limitation contained in the final sentence of subsection (d) herein, to encourage, accept, leverage, and administer private gifts for the benefit of, or in connection with, the environmental education and training activities and services of the United States Environmental Protection Agency;
(B) to conduct such other environmental education activities as will further the development of an environmentally conscious and responsible public, a well-trained and environmentally literate workforce, and an environmentally advanced educational system;
(C) to participate with foreign entities and individuals in the conduct and coordination of activities that will further opportunities for environmental education and training to address environmental issues and problems involving the United States and Canada or Mexico.
The Foundation develops, supports, and/or operates programs and projects to educate and train educational and environmental professionals, and to assist them in the development and delivery of environmental education and training programs and studies.
The Foundation has a governing Board of Directors (hereafter referred to in this section as `the Board'), which consists of 13 directors, each of whom shall be knowledgeable or experienced in the environment, education and/or training. The Board oversees the activities of the Foundation and assures that the activities of the Foundation are consistent with the environmental and education goals and policies of the Environmental Protection Agency and with the intents and purposes of the Act. The membership of the Board, to the extent practicable, represents diverse points of view relating to environmental education and training. Members of the Board are appointed by the Administrator of the Environmental Protection Agency.
Within 90 days of the date of the enactment of the National Environmental Education Act, and as appropriate thereafter, the Administrator will publish in the
Dr. Kiser is currently Vice President, Environment, Health, Safety and Sustainability for International Paper, a leading natural resources company that values environmental education, environmental stewardship and sustainability. Dr. Kiser has over 30 years of experience as a leader in corporate sustainability and social responsibility issues, having previously served in various capacities, including EHS Vice President for Eastman Kodak Company over a 29 year career with that firm. He is very well respected among his peers for his experience leading health, safety and environmental functions, for his abilities to help organizations manage change, and for his skills in motivating and managing people.
Dr. Kiser has a Ph.D. and a Masters in Physiology from Penn State and a Bachelor's Degree in Education from Western Michigan University. He has served as an instructor at Rochester Institute of Technology in that school's MBA program and is also a member of a wide variety of non-profit boards including The Nature Conservancy. In addition, Dr. Kiser started his career as a high school science and math teacher in Cedar Springs, Michigan.
Environmental Protection Agency (EPA).
Notice.
EPA has received a specific exemption request from the Texas Department of Agriculture to use the pesticide propazine (CAS No. 139-40-2) to treat up to 3,000,000 acres of cotton to control glyphosate-resistant Palmer amaranth. The applicant proposes the use of a pesticide that contains the active ingredient propazine, which belongs to the triazine class of pesticides. EPA is soliciting public comment before making the decision whether or not to grant the exemption.
Comments must be received on or before July 3, 2014.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2014-0419, by one of the following methods:
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Lois Rossi, Registration Division (7505P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; main telephone number: (703) 305-7090; email address:
You may be potentially affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. The following list of North American Industrial 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:
• Crop production (NAICS code 111).
• Animal production (NAICS code 112).
• Food manufacturing (NAICS code 311).
• Pesticide manufacturing (NAICS code 32532).
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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.
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Under section 18 of the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) (7 U.S.C. 136p), at the discretion of the EPA Administrator, a Federal or State agency may be exempted from any provision of FIFRA if the EPA Administrator determines that emergency conditions exist which require the exemption. Texas Department of Agriculture has requested the EPA Administrator to issue a specific exemption for the use of propazine on cotton to control glyphosate-resistant Palmer amaranth. Information in accordance with 40 CFR part 166 was submitted as part of this request.
As part of this request, the applicant asserts that propazine is needed to control glyphosate-resistant Palmer amaranth due to the lack of suitable alternatives and effective control practices; and significant economic losses will occur if this pest is not controlled.
The Applicant proposes to make no more than one application of Milo-Pro herbicide on up to 3,000,000 acres of cotton in Texas during the 2014 growing season. As currently proposed, the maximum amount of product to be applied would be 70,314 gallons.
This notice does not constitute a decision by EPA on the application itself. The regulations governing FIFRA section 18 require publication of a notice of receipt of an application for a specific exemption proposing the use of a pesticide that contains the active ingredient propazine, which belongs to the triazine class of pesticides. The notice provides an opportunity for public comment on the application.
The Agency will review and consider all comments received during the comment period in determining whether to issue the specific exemption requested by the Texas Department of Agriculture.
Environmental protection, Pesticides and pests.
Environmental Protection Agency.
Announcement of Meetings.
The Small Community Advisory Subcommittee (SCAS) will meet via teleconference on Thursday, July 3, 2014, 2:00 p.m.-2:30 p.m. (EDT). The Subcommittee will discuss small community issues related to EPA's Waters of the United States. This is an open meeting. Individuals or organizations wishing to address the Subcommittee meeting will be allowed a maximum of five minutes to present their point of view on issues pertaining to small communities.
The Local Government Advisory Committee (LGAC) will meet via
These are open meetings, and all interested persons are invited to participate. The Subcommittee will hear comments from the public between 2:15 p.m. and 2:30 p.m. on Thursday, July 3, 2014, and the Committee will hear comments from the public between 2:45 p.m. and 3:00 p.m. on Thursday, July 3, 2014. Individuals or organizations wishing to address the Subcommittee or the Committee will be allowed a maximum of five minutes to present their point of view. Also, written comments should be submitted electronically to
The Small Communities Advisory Subcommittee and Local Government Advisory Committee meetings will meet via teleconference. Meeting summaries will be available after the meeting online at
Local Government Advisory Committee (LGAC) and Small Communities Advisory Subcommittee (SCAS), contact Frances Eargle, Designated Federal Officer, at (202) 564-3115 or email at
Environmental Protection Agency (EPA).
Notice of meeting.
The Environmental Protection Agency (EPA) Science Advisory Board (SAB) Staff Office announces a joint public meeting of the Chartered SAB and the EPA's Office of Research and Development (ORD) Chartered Board of Scientific Counselors (BOSC) to develop strategic advice on ORD's research activities, six joint SAB-BOSC public teleconference calls to prepare for the face-to-face meeting, and one public teleconference to orient new SAB members to ORD's work.
The joint SAB-BOSC public meeting will be held on Thursday, July 24, 2014 from 10:00 a.m. to 5:30 p.m. and Friday, July 25, 2014 from 8:30 a.m. to 2:00 p.m. ET. There will be six joint SAB-BOSC teleconferences, one for each ORD research program. The joint SAB-BOSC teleconferences will be held: (1) For the Human Health Risk Assessment program on July 1, 2014, from 3:00 p.m. to 4:30 p.m. Eastern Time (ET); (2) for the Air, Climate and Energy program on July 3, 2014, from 10:00 a.m. to 12:00 p.m. ET; (3) for the Chemical Safety for Sustainability program on July 3, 2014, from 1:30 p.m. to 3:30 p.m. ET; (4) for the Homeland Security program on July 7, 2014, from 9:00 a.m. to 11:00 a.m. ET; (5) for the Sustainable and Health Communities program on July 10, 2014, from 2:00 p.m. to 4:00 p.m. ET; and (6) for the Safe and Sustainable Water Resources program on July 17, 2014, from 1:00 p.m. to 3:00 p.m. ET.
The teleconference to provide an overview of ORD's mission and role for SAB members will be held on June 24, 2014, from 10:00 a.m. to 12:00 p.m. ET.
All the teleconferences will be held by teleconference only. The face-to-face meeting will be held at the Washington Marriott Georgetown, 1221 22nd Street, Washington, DC 20037.
Any member of the public who wishes further information concerning the meetings may contact Dr. Angela Nugent, Designated Federal Officer (DFO), EPA Science Advisory Board (1400R), U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue NW., Washington, DC 20460; via telephone/voice mail (202) 564-2218, fax (202) 202-565-2098; or email at
The SAB was established pursuant to the Environmental Research, Development, and Demonstration Authorization Act (ERDDAA), codified at 42 U.S.C. 4365, to provide independent scientific and technical advice to the Administrator on the technical basis for Agency positions and regulations. The BOSC was established by the EPA to provide advice, information, and recommendations regarding the ORD research program. The SAB and BOSC are Federal Advisory Committees chartered under the Federal Advisory Committee Act (FACA), 5 U.S.C., App. 2. Pursuant to FACA and EPA policy, notice is hereby given that the chartered SAB and chartered BOSC will hold preparatory teleconferences and a joint meeting to develop advice on future directions for ORD's research programs. The SAB and BOSC will comply with the provisions of FACA and all appropriate SAB Staff Office procedural policies.
ORD research programs are structured to understand environmental problems and inform sustainable solutions to meet EPA's strategic goals. The research programs comprise six program areas: Air, Climate, and Energy; Safe and Sustainable Water Resources; Sustainable and Healthy Communities; Chemical Safety for Sustainability; Human Health Risk Assessment; and Homeland Security.
ORD requested that the SAB work jointly with the BOSC in 2011 to provide early advice on ORD strategic research directions. In response, the SAB and BOSC provided a report,
ORD is now requesting the SAB and BOSC to provide advice to inform the agency's development of Strategic Research Action Plans to cover the period 2016-2019. To address this request, the SAB and BOSC have planned a series of meetings: (1) A face-to-face meeting on this topic on July 24-25, 2014; (2) teleconferences devoted to each of the six ORD research so that ORD can brief SAB and BOSC members on ORD programs and so that SAB and BOSC members can discuss ORD's charge to their committees and preparations for the July 24-25, 2014 public meeting; and (3) a teleconference for ORD to provide a general background briefing on ORD's mission and role for new SAB members on June 24, 2014.
A meeting agenda and other materials for the meeting will be placed on the SAB Web site at
Public comment for consideration by EPA's federal advisory committees and panels has a different purpose from public comment provided to EPA program offices. Therefore, the process for submitting comments to a federal advisory committee is different from the process used to submit comments to an EPA program office.
Federal advisory committees and panels, including scientific advisory committees, provide independent advice to EPA. Members of the public can submit relevant comments for a federal advisory committee to consider as it develops advice for EPA. Interested members of the public may submit relevant written or oral information on the topic of this advisory activity, and/or the group conducting the activity, for the SAB and BOSC to consider during the advisory process. Input from the public to the SAB and BOSC will have the most impact if it provides specific scientific or technical information or analysis for them to consider or if it relates to the clarity or accuracy of the technical information. Members of the public wishing to provide comment should contact the DFO directly.
Written statements should be supplied in one of the following electronic formats: Adobe Acrobat PDF, MS Word, MS PowerPoint, or Rich Text files in IBM-PC/Windows 98/2000/XP format. It is the SAB Staff Office general policy to post written comments on the Web page for advisory meetings or teleconferences. Submitters are requested to provide an unsigned version of each document because the SAB Staff Office does not publish documents with signatures on its Web sites. Members of the public should be aware that their personal contact information, if included in any written comments, may be posted to the SAB Web site. Copyrighted material will not be posted without explicit permission of the copyright holder.
For information on access or services for individuals with disabilities, please contact Dr. Nugent at the phone number or email address noted above, preferably at least ten days prior to the meeting, to give EPA as much time as possible to process your request.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency (EPA) Science Advisory Board (SAB) Staff Office announces a public teleconference of the Chartered Clean Air Scientific Advisory Committee (CASAC) to conduct quality reviews of draft CASAC reports on EPA's Recommendation for an additional Federal Reference Method for Ozone and on EPA's Integrated Review Plan for the Primary National Ambient Air Quality Standard for Sulfur Dioxide
The teleconference will be held on Wednesday, July 16, 2014 from 10:00 a.m. to 1:00 p.m. (Eastern Time).
Any member of the public wishing to obtain information concerning the public teleconference may contact Mr. Aaron Yeow, Designated Federal Officer (DFO), via telephone at (202) 564-2050 or at
The CASAC was established pursuant to the Clean Air Act (CAA) Amendments of 1977, codified at 42 U.S.C. 7409(d)(2), to review air quality criteria and NAAQS and recommend any new NAAQS and revisions of existing criteria and NAAQS as may be appropriate. The CASAC shall also provide advice, information, and recommendations to the Administrator on the scientific and technical aspects of issues related to the criteria for air quality standards, research related to air quality, sources of air pollution, and of adverse effects which may result from various strategies to attain and maintain air quality standards. The CASAC is a Federal Advisory Committee chartered under the Federal Advisory Committee Act (FACA), 5 U.S.C., App. 2. Pursuant to FACA and EPA policy, notice is hereby given that the Chartered CASAC will hold a public teleconference to conduct quality reviews of draft CASAC reports on EPA's Recommendation for an Additional Federal Reference Method
The CASAC quality review process ensures that all draft reports developed by CASAC panels, committees or workgroups are reviewed and approved by the Chartered CASAC before being finalized and transmitted to the EPA Administrator. These reviews are conducted in a public meeting or teleconference as required by FACA.
The EPA is proposing the addition of the Nitric Oxide (NO)-Chemiluminescence method as an additional Federal Reference Method (FRM) for ozone. The CASAC Air Monitoring and Methods Subcommittee (AMMS) reviewed the scientific and technical aspects of a draft document that supports the EPA's recommendation to add the NO-Chemiluminescence method as an FRM and developed the draft report “Review of EPAs Recommendation for an Additional Federal Reference Method for Ozone-Nitric Oxide-Chemiluminescence”. The Chartered CASAC will conduct a quality review of this draft CASAC report. Background information about this advisory activity can be found on the CASAC Web site at
The EPA's Integrated Review Plan for the Primary NAAQS for Sulfur Dioxide (External Review Draft—March 2014) presents the planned approach for the review of the primary (health-based) NAAQS for sulfur oxides. The CASAC Augmented for Sulfur Oxides Panel reviewed this document and developed the report “Draft CASAC Review of the EPA's Integrated Review Plan for the Primary National Ambient Air Quality Standard for Sulfur Dioxide.” The Chartered CASAC will conduct a quality review of this draft CASAC report. Background information about this advisory activity can be found on the CASAC Web site at
Federal advisory committees and panels, including scientific advisory committees, provide independent advice to EPA. Members of the public can submit comments for a federal advisory committee to consider as it develops advice for EPA. Interested members of the public may submit relevant written or oral information on the topic of this advisory activity, and/or the group conducting the activity, for the CASAC to consider during the advisory process. Input from the public to the CASAC will have the most impact if it provides specific scientific or technical information or analysis for CASAC panels to consider or if it relates to the clarity or accuracy of the technical information. Members of the public wishing to provide comment should contact the DFO directly.
Environmental Protection Agency (EPA).
Notice.
EPA is announcing its receipt of test data submitted pursuant to a test rule issued by EPA under the Toxic Substances Control Act (TSCA). As required by TSCA, this document identifies each chemical substance and/or mixture for which test data have been received; the uses or intended uses of such chemical substance and/or mixture; and describes the nature of the test data received. Each chemical substance and/or mixture related to this announcement is identified in Unit I. under
Information about the following chemical substances and/or mixtures is provided in Unit IV.: D-gluco-heptonic acid, monosodium salt, (2.xi.)-(CAS No. 31138-65-5).
Section 4(d) of TSCA (15 U.S.C. 2603(d)) requires EPA to publish a notice in the
A docket, identified by the docket identification (ID) number EPA-HQ-OPPT-2013-0677, has been established for this
The docket for this
This unit contains the information required by TSCA section 4(d) for the test data D-gluco-heptonic acid, monosodium salt, (2.xi.) (CAS No. 31138-65-5)
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Environmental protection, Hazardous substances, Reporting and recordkeeping requirements.
Environmental Protection Agency.
Request for Nominations to the Clean Air Act Advisory Committee (CAAAC).
The U.S. Environmental Protection Agency (EPA) invites nominations from a diverse range of qualified candidates to be considered for appointment to its Clean Air Act Advisory Committee (CAAAC). Vacancies are anticipated to be filled by February 2015.
EPA is seeking nominations from academia, industry, non-governmental/environmental organizations, state and local government agencies, tribal governments, unions, trade associations, utilities, and lawyers/consultants. EPA values and welcomes diversity. In an effort to obtain nominations of diverse candidates, EPA encourages nominations of women and men of all racial and ethnic groups.
The following criteria will be used to evaluate nominees:
EPA will not appoint any federally-registered lobbyists to the committee. In addition, EPA's policy is that, unless otherwise prescribed by statute, members generally are appointed to two-year terms.
Please contact Jeneva Craig, Office of Air and Radiation, U.S. EPA at
Environmental Protection Agency (EPA).
Notice.
In accordance with the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA), EPA is issuing a notice of receipt of request for amendments by registrants to delete uses in certain pesticide registrations. FIFRA provides that a registrant of a pesticide product may at any time request that any of its pesticide registrations be amended to delete one or more uses. FIFRA further provides that, before acting on the request, EPA must publish a notice of receipt of any request in the
The deletions in Table 1 of Unit II, are effective July 18, 2014, because the registrants requested a waiver of the 180-day comment period, unless the Agency receives a written withdrawal request on or before July 18, 2014. The Agency will consider a written withdrawal request postmarked no later than July 18, 2014. The deletions in Table 2 of Unit II, are effective December 15, 2014, unless the Agency receives a written withdrawal request on or before December 15, 2014. The Agency will consider a written withdrawal request postmarked no later than December 15, 2014.
Users of these products who desire continued use on crops or sites being deleted should contact the applicable registrant in Table 1 of Unit II, before July 18, 2014, for the registrants that requested a waiver of the 180-day comment period. Users of these products who desire continued use on crops or sites being deleted should contact the applicable registrant in Table 2 of Unit II, before December 15, 2014.
Submit your withdrawal request, identified by docket identification (ID) number EPA-HQ-OPP-2014-0392, by one of the following methods:
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Additional instructions on visiting the docket, along with more information about dockets generally, is available at
Christopher Green, Information Technology and Resources Management Division (7502P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; main telephone number: (703) 347-0367; email address:
This action is directed to the public in general. Although this action may be of particular interest to persons who produce or use pesticides, the Agency has not attempted to describe all the specific entities that may be affected by this action.
The docket for this action, identified by docket ID number EPA-HQ-OPP-2014-0392, is available either electronically through
This notice announces receipt by the Agency of applications from registrants to delete uses in certain pesticide registrations. These registrations are listed in Table 1 & Table 2 of this unit by registration number, product name, active ingredient, and specific uses deleted:
Users of these products in Table 1 of this unit, who desire continued use on crops or sites being deleted should contact the applicable registrant before July 18, 2014, because the registrants requested a waiver of the 180-day comment period, to discuss withdrawal of the application for amendment. This 30-day period will also permit interested members of the public to intercede with registrants prior to the Agency's approval of the deletion.
Users of these products in Table 2 of this unit, who desire continued use on crops or sites being deleted should contact the applicable registrant before December 15, 2014, to discuss withdrawal of the application for amendment. This 180-day period will also permit interested members of the public to intercede with registrants prior to the Agency's approval of the deletion.
Table 3 of this unit includes the names and addresses of record for all registrants of the products listed in Table 1 & Table 2 of this unit, in sequence by EPA company number.
Section 6(f)(1) of FIFRA provides that a registrant of a pesticide product may at any time request that any of its pesticide registrations be amended to delete one or more uses. The FIFRA further provides that, before acting on the request, EPA must publish a notice of receipt of any such request in the
Registrants who choose to withdraw a request for use deletion must submit the withdrawal in writing to Christopher Green using the methods in
The Agency has authorized the registrants to sell or distribute product under the previously approved labeling for a period of 18 months after approval of the revision, unless other restrictions have been imposed, as in special review actions.
Environmental protection, Pesticides and pests.
Environmental Protection Agency (EPA).
Request for nominations for Clean Air Excellence Awards.
This notice announces the competition for the 2015 Clean Air Excellence Awards Program. The Environmental Protection Agency (EPA) established the Clean Air Excellence Awards Program in February 2000 to recognize outstanding and innovative efforts that support progress in achieving clean air.
All submissions of entries for the Clean Air Excellence Awards Program must be postmarked by September 12, 2014.
Additional information on this awards program, including the entry form, can be found on EPA's Clean Air Act Advisory Committee (CAAAC) Web site:
Environmental Protection Agency (EPA).
Notice.
In accordance with the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA), EPA is issuing a notice of receipt of a request by a registrant to voluntarily cancel certain pesticide registrations. EPA intends to issue a cancellation order granting this request at the close of the comment period for this announcement. If this request is granted, any sale, distribution, or use of products listed in this notice will be permitted after the registrations have been cancelled only if such sale, distribution, or use is consistent with the terms as described in the cancellation order.
Comments must be received on or before July 18, 2014.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2013-0049, by one of the following methods:
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•
Submit written withdrawal request by mail to: Pesticide Re-Evaluation Division (7508P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001. ATTN: Rusty Wasem.
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Rusty Wasem, Pesticide Re-Evaluation Division (7508P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (703) 305-6979; email address:
This action is directed to the public in general, and may be of interest to a wide range of stakeholders including environmental, human health, and agricultural advocates; the chemical industry; pesticide users; and members of the public interested in the sale, distribution, or use of pesticides.
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.
This notice announces receipt by the Agency of a request from Reckitt Benckiser LLC (Reckitt) to cancel 12 pesticide products registered under FIFRA section 3. These registrations are listed in sequence by registration number in Table 1 of this unit. The request for voluntary cancellation was conditioned on January 1, 2015 being the earliest effective date of cancellation, the Agency allowing certain sale and distribution of existing stocks of canceled product, and the Agency approving an alternative inert ingredient in the products prior to cancellation. EPA agreed to these conditions contingent upon:
1. Reckitt limiting further production of the 12 pesticide products, in the period prior to the effective date of cancellation, to filling orders from existing customers in accordance with shelf-set agreements and other contracts already in effect as of May 29, 2014;
2. Quantity limits on Reckitt's production of the 12 pesticide products; and
3. Reckitt submitting periodic reports on its production, sales and inventory of the 12 pesticide products.
At the end of the 30-day comment period, EPA intends to issue an order in the
Table 2 of this unit includes the address of Reckitt.
Section 6(f)(1) of FIFRA provides that a registrant of a pesticide product may at any time request that any of its pesticide registrations be canceled. FIFRA further provides that, before acting on the request, EPA must publish a notice of receipt of any such request in the
Section 6(f)(1)(B) of FIFRA requires that before acting on a request for voluntary cancellation, EPA must provide a 30-day public comment period on the request for voluntary cancellation or use termination. In addition, FIFRA section 6(f)(1)(C) requires that EPA provide a 180-day comment period on a request for voluntary cancellation or termination of any minor agricultural use before granting the request, unless:
1. The registrants request a waiver of the comment period, or
2. The EPA Administrator determines that continued use of the pesticide would pose an unreasonable adverse effect on the environment.
The products listed in Table 1 of Unit II. do not represent minor agricultural uses. Therefore, the requests are not eligible for a 180-day comment period.
Existing stocks are those stocks of canceled pesticide products that are in the United States and that were appropriately packaged, labeled, and released for shipment prior to the effective date of cancellation of the underlying registration. It is EPA's intention to issue a cancellation order treating existing stocks after cancellation of the registrations identified in Table 1 of Unit II. as follows:
1. Cancellation of the registrations will not become effective before January 1, 2015.
2. Reckitt will be permitted to sell and distribute existing stocks to its existing customers until March 31, 2015. During this time period, Reckitt will also be permitted to ship product for the purpose of returning material back to Reckitt or for the purpose of disposal.
3. Reckitt will be permitted to sell and distribute existing stocks after March 31, 2015 only for the limited purposes of returning material back to Reckitt or for disposal.
4. The sale and distribution of existing stocks by persons other than Reckitt (e.g., distributors, retailers) will be permitted until such stocks are exhausted. Users will be allowed to use existing stocks until such stocks are exhausted, provided that such use is consistent with the terms of the previously approved labeling on, or that accompanied, the canceled product.
Environmental protection, Pesticides and pests.
The following items have been adopted by the Commission and deleted from the list of consent agenda items scheduled for consideration at the Friday, June 13, 2014, Open Meeting and previously listed in the Commission's Notice of June 6, 2014.
The Federal Communications Commission will hold an Open Meeting on the subjects listed below on Friday, June 13, 2014 which is scheduled to commence at 10:30 a.m. in Room TW-C305, at 445 12th Street SW., Washington, DC.
The Commission will consider the following subjects listed below as a consent agenda and these items will not be presented individually:
The meeting site is fully accessible to people using wheelchairs or other mobility aids. Sign language interpreters, open captioning, and assistive listening devices will be provided on site. Other reasonable accommodations for people with disabilities are available upon request. In your request, include a description of the accommodation you will need and a way we can contact you if we need more information. Last minute requests will be accepted, but may be impossible to fill. Send an email to:
Additional information concerning this meeting may be obtained from Meribeth McCarrick, Office of Media Relations, (202) 418-0500; TTY 1-888-
For a fee this meeting can be viewed live over George Mason University's Capitol Connection. The Capitol Connection also will carry the meeting live via the Internet. To purchase these services, call (703) 993-3100 or go to
Copies of materials adopted at this meeting can be purchased from the FCC's duplicating contractor, Best Copy and Printing, Inc. (202) 488-5300; Fax (202) 488-5563; TTY (202) 488-5562. These copies are available in paper format and alternative media, including large print/type; digital disk; and audio and video tape. Best Copy and Printing, Inc. may be reached by email at
Federal Maritime Commission.
Notice and request for comments.
As part of our continuing effort to reduce paperwork and respondent burden, and as required by the Paperwork Reduction Act of 1995, the Federal Maritime Commission (Commission) invites comments on the continuing information collections (extensions with no changes) listed below in this notice.
Written comments must be submitted on or before August 20, 2014.
Address all comments to: Vern W. Hill, Managing Director, Office of the Managing Director, Federal Maritime Commission, 800 North Capitol Street NW., Washington, DC 20573, Phone: (202) 523-5800, Email:
Please send separate comments for each specific information collection listed below. You must reference the information collection's title and OMB number in your comments.
Copies of the information collections and instructions, or copies of any comments received, may be obtained by contacting Donna Lee on (202) 523-5800 or email at
The Commission, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to comment on the continuing information collections listed in this notice, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments submitted in response to this notice will be included or summarized in our request for Office of Management and Budget (OMB) approval of the relevant information collection. All comments are part of the public record and subject to disclosure. Please do not include any confidential or inappropriate material in your comments. We invite comments on: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
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 twelve days of the date this notice appears in the
By Order of the Federal Maritime Commission.
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 formally requested that the parties to the below listed agreement provide additional information pursuant to 46 U.S.C. 40304(d). This action prevents the agreement from becoming effective as originally scheduled. Interested parties may file comments within fifteen (15) days after publication of this notice in the
By Order of the Federal Maritime Commission.
1:00 p.m., Thursday, June 26, 2014.
The Richard V. Backley Hearing Room, Room 511N, 1331 Pennsylvania Avenue NW., Washington, DC 20004 (entry from F Street entrance).
Open.
The Commission will consider and act upon the following in open session:
Any person attending this meeting who requires special accessibility features and/or auxiliary aids, such as sign language interpreters, must inform the Commission in advance of those needs. Subject to 29 CFR 2706.150(a)(3) and 2706.160(d).
Jean Ellen (202) 434-9950/(202) 708-9300 for TDD Relay/1-800-877-8339 for toll free.
10:00 a.m., Thursday, June 26, 2014.
The Richard V. Backley Hearing Room, Room 511N, 1331 Pennsylvania Avenue NW., Washington, DC 20004 (entry from F Street entrance).
Open.
The Commission will hear oral argument in the matter
Any person attending this oral argument who requires special accessibility features and/or auxiliary aids, such as sign language interpreters, must inform the Commission in advance of those needs. Subject to 29 CFR 2706.150(a)(3) and 2706.160(d).
Jean Ellen (202) 434-9950/(202) 708-9300 for TDD Relay/1-800-877-8339 for toll free.
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 August 18, 2014.
You may submit comments, identified by
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•
•
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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
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—Office of the Chief Data Officer, 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 collection, which is being handled under this delegated authority, has received initial Board approval and is hereby published for comment. At the end of the comment period, the proposed information collection, 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 collection techniques or other forms of information technology; and
e. Estimates of capital or start up costs and costs of operation, maintenance, and purchase of services to provide information.
Additionally, depending upon the survey respondent, the information collection may be authorized under a more specific statute. Specifically, the Board is authorized to collect information from: BHCs (and their subsidiaries) under section 5(c) of the Bank Holding Company Act (12 U.S.C. 1844(c)); SLHCs under section 10(b)(2) of the Home Owners Loan Act (12 U.S.C. 1467a(b)(2)); non-BHC/SLHC SIFIs under section 161(a) of the Dodd-Frank Act (12 U.S.C. 5361(a)); the combined domestic operations of certain FBOs under section 8(a) of the International Banking Act of 1978 (12 U.S.C. 3106(a)) and section 5(c) of the Bank Holding Company Act (12 U.S.C. 1844(c)); SMBs under section 9 of the Federal Reserve Act (12 U.S.C. 324); Edge and agreement corporations under sections 25 and 25A of the Federal Reserve Act (12 U.S.C. 602 and 625) and U.S. branches and agencies of foreign banks under section 7(c)(2) of the International Banking Act of 1978 (12 U.S.C. 3105(c)(2) and under section 7(a) of the Federal Deposit Insurance Act (12 U.S.C. 1817(a)).
The Federal Reserve expects the majority of surveys to be conducted on a voluntary basis. However, with respect to collections of information from BHCs (and their subsidiaries), SLHCs, non-BHC/SLHC SIFIs, the combined domestic operations of certain foreign banking organizations, state member banks, Edge and agreement corporations, and U.S. branches and agencies for foreign banks authorized under the specific statutes noted above, the Federal Reserve could make the obligation to respond mandatory.
The ability of the Federal Reserve to maintain the confidentiality of information provided by respondents to the FR 3075 surveys will have to be determined on a case-by-case basis depending on the type of information provided for a particular survey. Depending upon the survey questions, confidential treatment may be warranted under exemptions 4, 6, and 8 of the Freedom of Information Act (FOIA). Exemption 4 protects from disclosure trade secrets and commercial or financial information, while exemption 6 protects information “the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.” See 5 U.S.C. 552(b)(4) and (b)(6). If the survey is mandatory and is undertaken as part of the supervisory process, information could be protected under FOIA exemption 8, which protects information relating to examination reports. 5 U.S.C. 552(b)(8).
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 August 18, 2014.
You may submit comments, identified by
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•
•
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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—Office of the Chief Data Officer, 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 collection, which is being handled under this delegated authority, has received initial Board approval and is hereby published for comment. At the end of the comment period, the proposed information collection, 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 collection techniques or other forms of information technology; and
e. Estimates of capital or start up costs and costs of operation, maintenance, and purchase of services to provide information.
U.S. domiciled affiliate is defined as a subsidiary, an associated company, or an entity treated as an associated company (e.g., a corporate joint venture) as set forth in the instructions for the Consolidated Financial Statements for Holding Companies (FR Y-9C;OMB No. 7100-0128). The proposed revision would be effective December 31, 2014.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The applications will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than July 14, 2014.
A. Federal Reserve Bank of Atlanta (Chapelle Davis, Assistant Vice President) 1000 Peachtree Street NE., Atlanta, Georgia 30309:
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The companies listed in this notice have given notice under section 4 of the Bank Holding Company Act (12 U.S.C. 1843) (BHC Act) and Regulation Y, (12 CFR part 225) to engage
Each notice is available for inspection at the Federal Reserve Bank indicated. The notice also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the question whether the proposal complies with the standards of section 4 of the BHC Act.
Unless otherwise noted, comments regarding the applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than July 3, 2014.
A. Federal Reserve Bank of Minneapolis (Jacquelyn K. Brunmeier, Assistant Vice President) 90 Hennepin Avenue, Minneapolis, Minnesota 55480-0291:
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10:00 a.m. (Eastern Time) June 23, 2014.
10th Floor Board Meeting Room, 77 K Street NE., Washington, DC 20002.
Open to the public.
Kimberly Weaver, Director, Office of External Affairs, (202) 942-1640.
Office of the Secretary, HHS.
Notice.
In compliance with section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the Office of the Secretary (OS), 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 a new collection. 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 July 18, 2014.
Submit your comments to
Information Collection Clearance Officer,
When submitting comments or requesting information, please include the Information Collection Request Title and document identifier HHS-OS-0990-new—30D for reference.
U.S. Department of Health and Human Services.
30-Day notice of submission of information collection approval from the Office of Management and Budget and request for comments.
As part of a Federal Government-wide effort to streamline the process to seek feedback from the public on service delivery, U.S. Department of Health and Human Services has submitted a Generic Information Collection Request (Generic ICR): “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery ” to OMB for approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501 et. seq.).
Comments on the ICR must be received on or before July 18, 2014.
Submit your comments to
Report Clearance Officer,
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior to fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
The Agency received no comments in response to the 60-day notice published in the
Below we provide U.S. Department of Health and Human Services projected average estimates for the next three years:
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 Office of Management and Budget control number.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a proposed collection of information has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.
Fax written comments on the collection of information by July 18, 2014.
To ensure that comments on the information collection are received, OMB recommends that written comments be faxed to the Office of Information and Regulatory Affairs, OMB, Attn: FDA Desk Officer, FAX: 202-395-7285, or emailed to
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
In compliance with 44 U.S.C. 3507, FDA has submitted the following proposed collection of information to OMB for review and clearance.
On June 22, 2009, the President signed the Family Smoking Prevention and Tobacco Control Act (Tobacco Control Act) (Public Law 111-31) into law. The Tobacco Control Act amended the Federal Food, Drug, and Cosmetic Act (the FD&C Act) by adding a chapter granting FDA important authority to regulate the manufacture, marketing, and distribution of tobacco products to protect the public health generally and to reduce tobacco use by minors.
The FD&C Act, as amended by the Tobacco Control Act, requires that before a new tobacco product may be introduced or delivered for introduction into interstate commerce, a manufacturer must submit a premarket application to FDA, and FDA must issue an order finding that the new product may be introduced or delivered for introduction into interstate commerce (section 910 of the FD&C Act (21 U.S.C. 387j)). An order under section 910 is not required, however, if a manufacturer submits a report under section 905(j) of the FD&C Act (21 U.S.C. 387e(j) demonstrating the new tobacco product's substantial equivalence to an appropriate predicate product, and FDA issues an order finding the new product to be substantially equivalent to the predicate product and in compliance with the requirements of the FD&C Act.
FDA has established a pathway for manufacturers to request exemptions from the substantial equivalence requirements of the FD&C Act in § 1107.1 (21 CFR 1107.1) of the Agency's regulations. As described in § 1107.1(a), FDA may exempt tobacco products that are modified by adding or deleting a tobacco additive, or increasing or decreasing the quantity of an existing tobacco additive, from the requirement of demonstrating substantial equivalence if the Agency determines that: (1) The modification would be a minor modification of a tobacco product; (2) a report demonstrating substantial equivalence is not necessary for the protection of public health; and (3) an exemption is otherwise appropriate.
Section 1107.1(b) states that a request for exemption under section 905(j)(3) of the FD&C Act may be made only by the manufacturer of a legally marketed tobacco product for a minor modification to that tobacco product and that the manufacturer must submit the request and all information supporting it to FDA. The request must be made in an electronic format that FDA can process, review, and archive (or a written request must be made by the manufacturer explaining in detail why the company cannot submit the request in an electronic format and requesting an alternative means of submission to the electronic format).
An exemption request must contain: (1) The manufacturer's address and contact information; (2) identification of the tobacco product(s); (3) a detailed explanation of the purpose for the modification; (4) a detailed description of the modification, including a statement as to whether the modification involves adding or deleting a tobacco additive, or increasing or decreasing the quantity of the existing tobacco additive; (5) a detailed explanation of why the modification is a minor modification of a tobacco product that can be sold under the FD&C Act; (6) a detailed explanation of why a report under section 905(j)(1) of the FD&C Act intended to demonstrate substantial equivalence is not necessary to ensure that permitting the tobacco product to be marketed would be appropriate for protection of the public health; (7) a certification (i.e., a signed statement by a responsible official of the company) summarizing the supporting evidence and providing the rationale for the official's determination that the modification does not increase the tobacco product's appeal to or use by minors, toxicity, addictiveness, or abuse liability; (8) other information justifying an exemption; and (9) an environmental assessment (EA) under part 25 (21 CFR part 25) prepared in accordance with the requirements of § 25.40.
The National Environmental Policy Act (NEPA) (42 U.S.C. 4321-4347) states national environmental objectives and imposes upon each Federal agency the duty to consider the environmental effects of its actions. Section 102(2)(C) of NEPA requires the preparation of an environmental impact statement for every major Federal action that will significantly affect the quality of the human environment.
The FDA NEPA regulations are contained in part 25. All applications for exemption from substantial equivalence require the submission of an EA. An EA provides information that is used to determine whether an FDA action could result in a significant environmental impact. Section 25.40(a) and (c) specifies the content requirements for EAs for nonexcluded actions.
The information required by § 1107.1(b) is submitted to FDA so FDA can determine whether an exemption from substantial equivalence to the product is appropriate for the protection of the public health. Section 1107.1(c) states that FDA will review the information submitted and determine whether to grant or deny an exemption based on whether the criteria in section 905(j)(3) of the FD&C Act are met. FDA may request additional information if necessary to make a determination and may consider the exemption request withdrawn if the information is not provided within the requested timeframe.
Section 1107.1(d) provides that FDA may rescind an exemption where necessary to protect the public health.
Section 905(j)(1)(A)(ii) of the FD&C Act states that if an exemption has been requested and granted, a report must be submitted to FDA that demonstrates that the tobacco product is modified within the meaning of section 905(j)(3), the modifications are to a product that is commercially marketed and in compliance with the requirements of the FD&C Act, and all of the modifications are covered by exemptions granted by the Secretary pursuant to section 905(j)(3).
In the
(Comment) Regarding the clarity of information collected, several comments indicated some confusion between the information being collected and the information needed to support an exemption request.
(Response) Section 1107.1(a) sets out the general requirements for requesting an exemption, but a manufacturer will need to determine how to meet the requirements for any of its new products that use the pathway. FDA intends to consider issuing a regulation or guidance to further clarify terms as experience is gained with the pathway.
(Comment) A few comments questioned the quality of the information being requested.
(Response) We disagree that the information required in an exemption request is not sufficient. We believe the information requested is what FDA needs to make a determination on an exemption request. Furthermore, several commenters also agreed with the sufficiency of the information needed to support an exemption request.
(Comment) Many comments addressed the accuracy of FDA's estimate of the burden for requesting a modification to an exemption request and questioned whether this burden was underestimated. Additionally, there was reference to the submittal of duplicative information.
(Response) FDA disagrees with these comments. We believe the burden estimates are appropriate and reflect the information needed by FDA when reviewing an exemption request. FDA also disagrees that there is duplicative information requested. The regulations implement the requirements of the FD&C Act for the exemption pathway to market. The commenters may be referring to the other notification and reporting requirements related to additives, such as those in section 904(c) of the FD&C Act (21 U.S. C. 387d(c)), but those requirements are not in the scope of this information collection.
FDA estimates the burden of this collection of information as follows:
FDA estimates that 500 requests for exemption will be submitted annually, and that it will take approximately 12 hours to prepare an exemption request. FDA also estimates that up to 30 percent (150) of the initial requests for information may require additional information in support of the initial exemption request, and it is expected that it will take an average of 3 hours to prepare the additional information. FDA also estimates that 750 manufacturers will take approximately 12 hours to prepare and submit an EA under part 25 in accordance with the requirements of § 25.40, as referenced in § 1107.1(b)(9).
FDA estimates that 750 respondents will take 3 hours to prepare a report under section 905(j)(1)(A)(ii) of the FD&C Act, which requires a manufacturer to submit a report at least 90 days prior to making an introduction or delivery into interstate commerce for commercial distribution of a tobacco product. The report will contain the manufacturer's basis that the tobacco product is modified within the meaning of section 905(j)(3) of the FD&C Act, the modifications are to a product that is commercially marketed and compliant with the FD&C Act, the modifications are covered by exemptions granted pursuant to section 905(j)(3), and a listing of actions taken to comply with any applicable requirements of section 907 of the FD&C Act (21 U.S.C. 387g). FDA's estimates are based on experience with and information on other FDA-regulated products and indications from industry.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “Adverse Event Program for Medical Devices (Medical Product Safety Network (MedSun))” has been approved by the Office of Management and
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002
On April 22, 2014, the Agency submitted a proposed collection of information entitled “Adverse Event Program for Medical Devices (Medical Product Safety Network (MedSun))” to OMB for review and clearance under 44 U.S.C. 3507. 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. OMB has now approved the information collection and has assigned OMB control number 0910-0471. The approval expires on May 31, 2017. A copy of the supporting statement for this information collection is available on the Internet at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA or Agency) is announcing the availability of a draft guidance for industry entitled “Internet/Social Media Platforms with Character Space Limitations: Presenting Risk and Benefit Information for Prescription Drugs and Medical Devices.” This draft guidance responds to, among other things, stakeholder requests for specific guidance and describes FDA's current thinking on how manufacturers, packers, and distributors (firms) of prescription human and animal drugs (drugs) and medical devices for human use (devices), including biological products, that choose to present benefit information should present both benefit and risk information within advertising and promotional labeling of their FDA-regulated medical products on electronic/digital platforms that are associated with character space limitations, specifically on the Internet and through social media or other technological venues (Internet/social media). The draft guidance represents FDA's current thinking on specific aspects of FDA's evolving consideration of social media platforms and other Internet-related matters. FDA continues actively to review, analyze, and develop approaches to a variety of topics related to the labeling and advertising of medical products, including the development of this and other guidance addressing the use of social media platforms and the Internet.
Although you can comment on any guidance at any time (see 21 CFR 10.115(g)(5)), to ensure that the Agency considers your comments on this draft guidance before it begins work on the final version of the guidance, submit either electronic or written comments on the draft guidance by September 16, 2014.
Submit written requests for single copies of the draft guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 2201, Silver Spring, MD 20993-0002; or to the Office of Communication, Outreach and Development, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 3128, Silver Spring, MD 20993-0002; or to the Office of the Center Director, Guidance and Policy Development, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 5431, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the
Submit electronic comments on the draft guidance to
FDA is announcing the availability of a draft guidance for industry entitled “Internet/Social Media Platforms with Character Space Limitations: Presenting Risk and Benefit Information for Prescription Drugs and Medical Devices.”
On November 12 and 13, 2009, FDA held a public hearing entitled “Promotion of Food and Drug Administration—Regulated Medical Products Using the Internet and Social Media Tools” to provide an opportunity for broad public participation and comment on the following questions that relate specifically to promotional issues:
1. For what online communications are manufacturers, packers, or distributors accountable?
2. How can manufacturers, packers, or distributors fulfill regulatory requirements (e.g., fair balance, disclosure of indication and risk information, and postmarketing submission requirements) in their internet and social media promotion, particularly when using tools that are associated with space limitations and tools that allow for real-time communications (e.g., microblogs and mobile technology)?
3. What parameters should apply to the posting of corrective information on Web sites controlled by third parties?
4. When is the use of links appropriate?
Subsequent to the live testimony heard at the public hearing, FDA received 72 comments to the docket.
Specifically, this draft guidance presents considerations to illustrate FDA's thinking on factors that are relevant to the communication of benefit and risk information on Internet/social media platforms with character space limitations. Examples of Internet/
Please note that this draft guidance does not address promotion via product Web sites, Web pages on social media networking platforms (e.g., individual product pages on Web sites such as Facebook, Twitter, YouTube), and online Web banners as the Agency believes that these specific types of Internet/social media platforms do not impose the same character space constraints as online microblog messaging and online paid search. This draft guidance also does not address responsive Web design or other technology-specific layout features that may result in product promotion presentations that differ depending on the technology used to view them (e.g., desktop computer monitors, mobile devices, tablets).
This draft guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft guidance, when finalized, will represent the Agency's current thinking on presenting risk and benefit information for prescription drugs and medical devices on Internet/social media platforms with character space limitations. It does not create or confer any rights for or on any person and does not operate to bind FDA or the public. An alternative approach may be used if such approach satisfies the requirements of the applicable statutes and regulations.
This draft guidance contains information collection provisions that are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501-3520). The collections of information in 21 CFR 202.1 and 21 CFR parts 801 and 809 have been approved under OMB control numbers 0910-0686 and 0910-0485, respectively. In accordance with the PRA, prior to publication of any final guidance document, FDA intends to solicit public comment and obtain OMB approval for any information collections recommended in this guidance that are new or that would represent material modifications to previously approved collections of information found in FDA regulations or guidances.
Interested persons may submit either electronic comments regarding this document to
Persons with access to the Internet may obtain the document at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA or Agency) is announcing the availability of a draft guidance for industry entitled “Internet/Social Media Platforms: Correcting Independent Third-Party Misinformation About Prescription Drugs and Medical Devices.” This draft guidance responds to (among other things) stakeholder requests for specific guidance and describes FDA's current thinking on how manufacturers, packers, and distributors (firms) of prescription human and animal drugs (drugs) and medical devices for human use (devices), including biological products, should respond, if they choose to respond, to misinformation related to a firm's own FDA-approved or cleared products when that information is created or disseminated by independent third parties. This draft guidance updates and clarifies FDA's policies on the correction of misinformation created or disseminated by independent third parties on the Internet or through social media platforms, regardless of whether that misinformation appears on a firm's own forum or an independent third-party forum or Web site. The draft guidance represents FDA's current thinking on specific aspects of FDA's evolving consideration of social media platforms and other Internet-related matters. FDA continues actively to review, analyze, and develop approaches to a variety of topics related to the labeling and advertising of medical products, including the development of this and other guidance addressing the use of social media platforms and the Internet.
Although you can comment on any guidance at any time (see 21 CFR 10.115(g)(5)), to ensure that the Agency considers your comments on this draft guidance before it begins work on the final version of the guidance, submit either electronic or written comments on the draft guidance by September 16, 2014. Submit written comments on the proposed collection of information by August 18, 2014.
Submit written requests for single copies of the draft guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 2201, Silver Spring, MD 20993-0002; to the Office of Communication, Outreach and Development, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 3128, Silver Spring, MD 20993-0002; to the Communications Staff (HFV-12), Center for Veterinary Medicine, Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855; or to the Office of the Center Director, Guidance and Policy Development, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 5431, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the
Submit electronic comments on the draft guidance to
FDA is announcing the availability of a draft guidance for industry entitled “Internet/Social Media Platforms: Correcting Independent Third-Party Misinformation About Prescription Drugs and Medical Devices.” On November 12-13, 2009, FDA held a public hearing entitled “Promotion of Food and Drug Administration-Regulated Medical Products Using the Internet and Social Media Tools” to provide an opportunity for broad public participation and comment on the following questions that relate specifically to promotional issues:
1. For what online communications are manufacturers, packers, or distributors accountable?
2. How can manufacturers, packers, or distributors fulfill regulatory requirements (e.g., fair balance, disclosure of indication and risk information, and postmarketing submission requirements) in their Internet and social media promotion, particularly when using tools that are associated with space limitations and tools that allow for real-time communications (e.g., microblogs and mobile technology)?
3. What parameters should apply to the posting of corrective information on Web sites controlled by third parties?
4. When is the use of links appropriate?
This draft guidance provides FDA's recommendations regarding how manufacturers, packers, and distributors of prescription human and animal drugs and medical devices for human use, including biological products, should respond, if they choose to respond, to misinformation created or disseminated by independent third parties related to a firm's own FDA-approved or cleared products on the Internet or through social media platforms.
This draft guidance provides FDA's recommendations to firms that voluntarily choose to correct misinformation that appears on the Internet or through social media platforms. This draft guidance discusses the type of information that is considered misinformation, recommends parameters for corrective information, and recommends approaches to correcting misinformation. It refers only to misinformation that is created or disseminated by an independent third party and that is not produced by, or on behalf of, or prompted by the firm in any particular. When a firm chooses to correct misinformation in a truthful and non-misleading manner and according to the recommendations in this draft guidance, FDA does not intend to object if the corrective information voluntarily provided by the firm does not satisfy otherwise applicable regulatory requirements regarding labeling or advertising, if any. If a firm chooses to respond to misinformation about its products using non-truthful or misleading information or in a manner other than that recommended in this draft guidance, however, FDA may object if the information provided by the firm does not comply with applicable regulatory requirements related to labeling or advertising, if any.
This draft guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft guidance, when finalized, will represent the Agency's current thinking on correcting misinformation created or disseminated by independent third parties. It does not create or confer any rights for or on any person and does not operate to bind FDA or the public. An alternative approach may be used if such approach satisfies the requirements of the applicable statutes and regulations.
Under the Paperwork Reduction Act of 1995 (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 collected; and (4) ways to minimize the burden of information collected on the respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
The draft guidance explains FDA's current policy position that a firm may voluntarily correct misinformation about its own FDA-approved or -cleared products that is created or disseminated by independent third parties who are not under the firm's control or
Because the draft guidance recommends that a firm disclose certain information to others when correcting misinformation created or disseminated by independent third parties, this “third-party disclosure” constitutes a “collection of information” under the PRA. In addition, the PRA is triggered because the draft guidance also recommends that a firm maintain certain records related to this disclosure—the content of the misinformation, where the misinformation appeared, the date the misinformation appeared or was located, the corrective information that was provided, and the date the corrective information was provided.
Specifically, the draft guidance recommends that firms provide appropriate truthful and non-misleading corrective information, or alternatively, it may provide a reputable source from which to obtain the correct information. For the purposes of the draft guidance, to be considered “appropriate corrective information,” a firm's communication should:
• Be relevant and responsive to the misinformation;
• Be limited and tailored to the misinformation;
• Be non-promotional in nature, tone, and presentation;
• Be accurate;
• Be consistent with the FDA-required labeling for the product;
• Be supported by sufficient evidence, including substantial evidence, when appropriate, for prescription drugs;
• Either be posted in conjunction with the misinformation in the same area or forum (if posted directly to the forum by the firm), or should reference the misinformation and be intended to be posted in conjunction with the misinformation (if provided to the forum operator or author); and
• Disclose that the person providing the corrective information is affiliated with the firm that manufactures, packs, or distributes the product.
The FDA-required labeling should be included or provided in a readily accessible format. (As two examples, a firm may provide a link that goes directly to the FDA-required labeling or may provide a link that opens a new window to a portable document format (PDF) file.)
The draft guidance also recommends that a firm correct all the misinformation in one clearly defined portion of a forum, but it is not expected to correct each occurrence of independent third-party misinformation throughout an entire forum. When a firm decides to correct all the misinformation in one clearly defined portion of a forum, the firm should clearly identify the misinformation it is correcting, define the portion of the forum it is correcting, describe the location or the nature of the misinformation that was corrected, and provide a date the correction is made.
A firm may provide the correct information to the independent author for the author to incorporate or request the author remove the misinformation or allow comments to be posted. The firm may request that the site administrator remove the misinformation or allow comments to be posted.
FDA estimates that approximately 400 firms annually undertake correcting 50 pieces of misinformation created or disseminated by independent third parties on the Internet or through social media. FDA estimates that it will take firms approximately 3 hours to correct misinformation as recommended in the draft guidance.
FDA also estimates that approximately 20,000 records will be maintained by firms that have chosen to correct misinformation created or disseminated by independent third parties on the Internet or through social media and that each record will take approximately 30 minutes to prepare and maintain.
In addition to general comments, FDA specifically requests comments on the following issue: The draft guidance recommends that a firm should identify the misinformation or define the portion of the forum it is correcting and should correct all the misinformation that appears in that clearly defined portion. Is this an appropriate and effective way for firms to correct misinformation without correcting all misinformation that might appear in a forum? When or under what conditions should a sponsor choose a specific portion of a forum to correct? What factors, such as the platform(s) or technology(ies) that can be used to view the forum, the relative location of pieces of misinformation the firm chooses to correct, the nature of the forum, the quantity of information, and the length of time the forum encompasses, should be taken into account in choosing the portion of a forum to correct?
Interested persons may submit either electronic comments regarding this
Persons with access to the Internet may obtain the document at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that it has received a petition requesting exemption from the premarket notification requirements for a wheelchair elevator device commonly known as a manually operated portable wheelchair lift. This device is used to provide a means for a disabled person to move a wheelchair from one level to another. FDA is publishing this notice to obtain comments in accordance with procedures established by the Food and Drug Administration Modernization Act of 1997 (FDAMA).
Submit either electronic or written comments by July 18, 2014.
You may submit comments, identified by Docket No. FDA-2014-P-0231, by any of the following methods:
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
Submit written submissions in the following way:
• Mail/Hand delivery/Courier (for paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
Michael J. Ryan, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 1615, Silver Spring, MD 20993-0002, 301-796-6283,
Under section 513 of the Federal Food, Drug, and Cosmetic Act (the FD&C Act) (21 U.S.C. 360c), FDA must classify devices into one of three regulatory classes: Class I, class II, or class III. FDA classification of a device is determined by the amount of regulation necessary to provide a reasonable assurance of safety and effectiveness. Under the Medical Device Amendments of 1976 (1976 amendments) (Public Law 94-295), as amended by the Safe Medical Devices Act of 1990 (Public Law 101-629), devices are to be classified into class I (general controls) if there is information showing that the general controls of the FD&C Act are sufficient to assure safety and effectiveness; into class II (special controls) if general controls, by themselves, are insufficient to provide reasonable assurance of safety and effectiveness, but there is sufficient information to establish special controls to provide such assurance; and into class III (premarket approval) if there is insufficient information to support classifying a device into class I or class II and the device is a life sustaining or life supporting device, or is for a use which is of substantial importance in preventing impairment of human health or presents a potential unreasonable risk of illness or injury.
Most generic types of devices that were on the market before the date of the 1976 amendments (May 28, 1976) (generally referred to as preamendments devices) have been classified by FDA under the procedures set forth in section 513(c) and (d) of the FD&C Act through the issuance of classification regulations into one of these three regulatory classes. Devices introduced into interstate commerce for the first time on or after May 28, 1976 (generally referred to as postamendments devices), are classified through the premarket notification process under section 510(k) of the FD&C Act (21 U.S.C. 360(k). Section 510(k) of the FD&C Act and the implementing regulations, 21 CFR part 807, require persons who intend to market a new device to submit a premarket notification (510(k)) containing information that allows FDA to determine whether the new device is “substantially equivalent” within the meaning of section 513(i) of the FD&C Act to a legally marketed device that does not require premarket approval.
On November 21, 1997, the President signed into law FDAMA (Public Law 105-115). Section 206 of FDAMA, in part, added a new section, 510(m), to the FD&C Act. Section 510(m)(1) of the FD&C Act requires FDA, within 60 days after enactment of FDAMA, to publish in the
Section 510(m)(2) of the FD&C Act provides that 1 day after date of publication of the list under section 510(m)(1), FDA may exempt a device on its own initiative or upon petition of an interested person if FDA determines that a 510(k) is not necessary to provide reasonable assurance of the safety and
There are a number of factors FDA may consider to determine whether a 510(k) is necessary to provide reasonable assurance of the safety and effectiveness of a class II device. These factors are discussed in the guidance the Agency issued on February 19, 1998, entitled “Procedures for Class II Device Exemptions from Premarket Notification, Guidance for Industry and CDRH Staff.” That guidance is available through the Internet at
FDA has received the following petition requesting an exemption from premarket notification for a class II device: Dave Smith, on behalf of Adaptive Engineering, Inc., for its wheelchair elevator device (commonly known as a manually operated portable wheelchair lift), classified under 21 CFR 890.3930.
Interested persons may submit either electronic comments regarding this document to
Health Resources and Services Administration, HHS.
Notice.
In compliance with the requirement for opportunity for public comment on proposed data collection projects (Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995), the Health Resources and Services Administration (HRSA) announces plans to submit an Information Collection Request (ICR), described below, to the Office of Management and Budget (OMB). Prior to submitting the ICR to OMB, HRSA seeks comments from the public regarding the burden estimate, below, or any other aspect of the ICR.
Comments on this Information Collection Request must be received no later than August 18, 2014.
Submit your comments to
To request more information on the proposed project or to obtain a copy of the data collection plans and draft instruments, email
When submitting comments or requesting information, please include the information request collection title for reference.
Each of the 50 states, the District of Columbia, Puerto Rico, and several territories receive ADAP grants. As part of the funding requirements, ADAPs submit reports concerning information on patients served, eligibility requirements, pharmaceuticals prescribed, pricing and other sources of support to provide AIDS medication treatment, cost data, and coordination with Medicaid. Since 2005, ADAPs have supplied aggregate data to HRSA using the ADAP Quarterly Report (AQR). However, aggregate data cannot be analyzed with the detail that is required to assess quality of care or to sufficiently account for the use of Ryan White HIV/AIDS Program Funds. To address this limitation, HRSA's HIV/AIDS Bureau (HAB) developed a client-level data system for ADAPs called the ADAP Data Report (ADR), and in 2013 ADAPs began submitting the ADR. As of April 30, 2014, HAB retired the AQR and now only requires the submission of the ADR. The ADR will be submitted annually and consists of a Grantee Report and a client-level data file.
On April 11, 2012, a memo from the Secretary of HHS directed HRSA with other HHS Operating Divisions (OpDivs) to work together to: (1) Identify seven common core HIV/AIDS indicators; (2) develop implementation plans to deploy these indicators; and (3) streamline data collection and reduce reporting by at least 20 to 25 percent. In November 2012, the HIV/AIDS Indicators Implementation Group (HAIIG), comprised of representatives from HHS OpDivs, the Department of Housing and Urban Development, the Veterans' Health Administration, and community partners successfully identified the required common core HIV/AIDS indicators.
Revisions to the ADR are required to support implementation of the core
In addition to the new data elements noted above, other new variables will be added to the ADR to address provisions set forth in Section 4302 of the Affordable Care Act (ACA). The ACA includes several provisions aimed at eliminating health disparities in America. Section 4302 (Understanding health disparities: Data collection and analysis) of the ACA focuses on the standardization, collection, analysis, and reporting of health disparities data. Section 4302 requires the Secretary of DHHS to establish data collection standards for race, ethnicity, and sex. The race/ethnicity data elements include reporting of Hispanic, Asian, and Native Hawaiian/Pacific Islander subgroups. The categories for HHS data standards for race and ethnicity are based on the disaggregation of the OMB standard used in the American Community Survey (ACS) and the 2000 and 2010 Decennial Census. The subgroup categories can be rolled-up to the OMB standard. These new data elements will be used in data analysis intended to identify and understand health disparities.
Total Estimated Annualized burden hours:
HRSA specifically requests comments on (1) the necessity and utility of the proposed information collection for the proper performance of the agency's functions, (2) the accuracy of the estimated burden, (3) ways to enhance the quality, utility, and clarity of the information to be collected, and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
Health Resources and Services Administration, HHS.
Notice.
In compliance with the requirement for opportunity for public comment on proposed data collection projects (Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995), the Health Resources and Services Administration (HRSA) announces plans to submit an Information Collection Request (ICR), described below, to the Office of Management and Budget (OMB). Prior to submitting the ICR to OMB, HRSA seeks comments from the public regarding the burden estimate, below, or any other aspect of the ICR.
Comments on this Information Collection Request must be received no later than August 18, 2014.
Submit your comments to
To request more information on the proposed project or to obtain a copy of the data collection plans and draft instruments, email
When submitting comments or requesting information, please include the information request collection title for reference.
Total Estimated Annualized burden hours:
HRSA specifically requests comments on (1) the necessity and utility of the proposed information collection for the proper performance of the agency's functions, (2) the accuracy of the estimated burden, (3) ways to enhance the quality, utility, and clarity of the information to be collected, and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, for opportunity for public comment on proposed data collection projects, the National Cancer Institute (NCI), National Institutes of Health (NIH), will publish periodic summaries of proposed projects to be submitted to the Office of Management and Budget (OMB) for review and approval.
Written comments and/or suggestions from the public and affected agencies are invited on one or more of the following points: (1) Whether the proposed collection of information is necessary for the proper performance of the function of the agency, including whether the information will have practical utility; (2) 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; (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 those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
The information to be collected will be aggregate descriptive information and protocols. Though the CEDCD has a biospecimen component (similar to the Specimen Resource Locator), the CEDCD is not a biospecimen locator database. It is a database focusing exclusively on descriptive data pertaining to large, prospective epidemiology cohorts.
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 425.
Under the provisions of Section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the National Institutes of Health (NIH) has submitted to the Office of Management and Budget (OMB) a request for review and approval of the information collection listed below. This proposed information collection was previously published in the
To obtain a copy of the data collection plans and instruments or request more information on the proposed project contact either: Dr. Larissa Aviles-Santa, 6701 Rockledge, Epidemiology Branch, Program in Prevention and Population Sciences, Division of Cardiovascular Sciences, National Heart, Lung, and Blood Institute, National Institutes of Health, 6701 Rockledge Dr., MSC 7936, Bethesda, MD 20892-7936, or call non-toll-free number 301-435-0450, or Email your request, including your address to
1. Examination of the cohort following a standardized protocol, which consisted of interviews and clinical measurements to assess physiological and biochemical measurements including DNA/RNA extraction for ancillary genetic research studies.
2. Follow-up of the cohort, which consists of an annual telephone interview to assess vital status, changes in health status and medication intake, and new cardiovascular and pulmonary events (including fatal and non-fatal myocardial infarction and heart failure; fatal and non-fatal stroke; and exacerbation of asthma and chronic obstructive pulmonary disease).
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 30,940.
30-Day Notice of Information Collection for review; Student and Exchange Visitor Information System (SEVIS); OMB Control No. 1653-0038.
The Department of Homeland Security, U.S. Immigration and Customs Enforcement (USICE), is submitting the following information collection request for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection is published in the
Written comments and suggestions regarding items contained in this notice and especially with regard to the estimated public burden and associated
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(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 agencies estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(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, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
(1)
(2)
(3)
(4)
(5)
(6)
Office of the Assistant Secretary for Public and Indian Housing, HUD.
Notice.
On March 23, 2012, HUD published a notice, effective as of March 23, 2012, that established the policies and procedures for the administration of tenant-based Section 8 Housing Choice Voucher (HCV) rental assistance under the HUD-Veterans Affairs Supportive Housing (HUD-VASH) program. The March 23, 2012, notice was an update of a HUD-VASH program notice first published by HUD on May 6, 2008. It was recently brought to HUD's intention that one of the HUD regulations that requires waiver in order to allow HUD-VASH families to live on the grounds of a VA facility in units developed to house homeless veterans was not referenced in either the May 6, 2008, notice or the March 23, 2012, notice. Although HUD has waived the requirement since the issuance of the May 6, 2008, notice, the regulatory requirement was inadvertently omitted from the notice. This notice corrects that omission.
Michael S. Dennis, Director, Office of Housing Voucher Programs, Office of Public Housing and Vouchers Programs,
The HUD-VASH program was authorized pursuant to Division K, Title II, of the Consolidated Appropriations Act, 2008 (Public Law 110-161, approved December 26, 2007) under the heading “Tenant-Based Rental Assistance” (FY 2008 Appropriations). The HUD-VASH program combines HCV rental assistance for homeless veterans with case management and clinical services provided by the VA through its community medical centers. The program is administered by PHAs that partner with local VA medical facilities. Since implementation of the program, ongoing VA case management, health, and other supportive services have been made available to homeless veterans at more than 300 VA Medical Center (VAMC) supportive services sites and Community-Based Outpatient Clinics (CBOCs) across the nation. The HUD-VASH program is a key component of reducing homelessness among veterans as outlined in the Administration's Federal Strategy to Prevent and End Homelessness.
Following enactment of the FY 2008 Appropriations, HUD published a notice on May 6, 2008, at 73 FR 25026, which established the policies and procedures for the administration of tenant-based Section 8 HCV rental assistance under the HUD-VASH program. The appropriations acts following the FY 2008 Appropriations Act continued to fund the HUD-VASH program.
By notice published on March 23, 2012, at 77 FR 17086, HUD updated the policies and procedures for the administration of the HUD-VASH program, republishing these policies and procedures in their entirety. In addition to updating the 2008 policies and procedures, the March 23, 2012, notice was also issued to provide new and clarifying guidance regarding several aspects of the program such as those pertaining to certain types of verification documentation, addition of family members after the veteran is a participant in the HCV program, termination of assistance, portability moves within the same catchment area where both PHAs have received HUD-VASH vouchers, portability moves when case management is no longer required, reallocation of HUD-VASH vouchers, and Housing Quality Standards (HQS) initial inspections.
It was recently brought to HUD's attention that one of the HUD regulations that requires waiver in order to allow HUD-VASH families to live on the grounds of a VA facility in units developed to house homeless veterans was not referenced in either the May 6, 2008, notice or the March 23, 2012, notice. Section II.e. of the May 6, 2008, notice, and Section II.f. of the March 23, 2012, notice, which each address ineligible housing, reference waiver of HUDs regulation at 24 CFR 982.352(a)(5) (which covers section 8 housing choice voucher tenant-based assistance) but inadvertently omitted reference to a corresponding provision covering section 8 project-based voucher assistance, specifically, 24 CFR 983.53(a)(2). The latter provision also must be waived to fulfill HUD's intent of allowing VASH families (whether receiving tenant-based or project-based assistance) to live on the grounds of a VA facility. Although § 983.53(a)(2) was inadvertently omitted in each of these notices, the waiver of § 983.53(a)(2) has been applied by HUD as if the regulatory section had been included in the initial May 6, 2008, notice.
This notice published today corrects the paragraph on ineligible housing in the March 23, 2012, notice to include reference to 24 CFR 983.53(a)(2). Since the March 23, 2012, notice was an update of the May 6, 2008, notice there is no need to make the technical correction to the May 6, 2008, notice.
HUD's notice published on March 23, 2012, at 77 FR 17086, specifically subsection II.f. entitled “Ineligible Housing,” and found at 77 FR 17089 (middle column) is corrected to read as follows:
HUD-VASH families will be permitted to live on the grounds of a VA facility in units developed to house homeless veterans. Therefore, 24 CFR 982.352(a)(5) and 983.53(a)(2), which prohibit units on the physical grounds of a medical, mental, or similar public or private institution, are waived for that purpose only.
National Park Service, Interior.
Notice of Meeting.
As required by the Federal Advisory Committee Act (5 U.S.C. Appendix 1-16), the National Park Service (NPS) is hereby giving notice that the Advisory Council for the Star-Spangled Banner National Historic Trail will hold a meeting. The trail commemorates the Chesapeake Campaign of the War of 1812, including the British invasion of Washington, District of Columbia, and its associated feints, and the Battle of Baltimore in summer 1814.
This meeting is open to the public. Preregistration is required for both public attendance and comment. Any individual who wishes to attend the meeting and/or participate in the public comment session should register via email at
The Star-Spangled Banner National Historic Trail Advisory Council will meet from 10:00 a.m. to 3:00 p.m. on Wednesday, July 9, 2014 (eastern).
The meeting will be held at the Maryland Archaeological Conservation Lab at Jefferson Patterson Park & Museum, 10515 Mackall Road, St. Leonard, MD 20685.
Christine Lucero, Partnership Coordinator, Chesapeake Bay Office, telephone (757) 258-8914 or email
Under section 10(a)(2) of the Federal Advisory Committee Act (5 U.S.C. Appendix 1-16), this notice announces a meeting of the Star-Spangled Banner National Historic Trail Advisory Council. Topics to be discussed include setting priorities for the trail in the coming years and the potential creation of a “Friends Group.”
The Council meeting is open to the public. Comments will be taken for 30 minutes at the end of the meeting (from
Bureau of Ocean Energy Management (BOEM), Interior.
Proposed Sale Notice for Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore Massachusetts.
This document is the Proposed Sale Notice (PSN) for the sale of commercial wind energy leases on the Outer Continental Shelf (OCS) offshore Massachusetts, pursuant to BOEM's regulations at 30 CFR 585.216. BOEM proposes to offer for sale four leases: Lease OCS-A 0500, Lease OCS-A 0501, Lease OCS-A 0502, and Lease OCS-A 0503. BOEM proposes to use a multiple-factor auction format for the lease sale. In this PSN, you will find information pertaining to the areas available for leasing, proposed lease provisions and conditions, auction details, the lease form, criteria for evaluating competing bids, award procedures, appeal procedures, and lease execution. BOEM invites comments during a 60-day comment period following publication of this notice. The issuance of the leases that would result from this proposed sale would not constitute approval of project-specific plans to develop offshore wind energy. Such plans, expected to be submitted by successful lessees, will be subject to subsequent environmental and public review prior to a decision to proceed with development.
Comments should be submitted electronically or postmarked no later than August 18, 2014. All comments received or postmarked during the comment period will be made available to the public and considered prior to publication of the Final Sale Notice (FSN).
All bidders interested in participating in the lease sale who have not previously been qualified by BOEM to participate in this lease sale must submit the required qualification materials by the end of the 60-day comment period for this notice. All qualification materials must be postmarked no later than August 18, 2014.
Potential auction participants, Federal, state, and local government agencies, tribal governments, and other interested parties are requested to submit their written comments on the PSN in one of the following ways:
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If you wish to protect the confidentiality of your comments or qualification materials, clearly mark the relevant sections and request that BOEM treat them as confidential. Please label privileged or confidential information with the caption “Contains Confidential Information” and consider submitting such information as a separate attachment. Treatment of confidential information is addressed in the section of this PSN entitled “Protection of Privileged or Confidential Information.” Information that is not labeled as privileged or confidential will be regarded by BOEM as suitable for public release.
Jessica Stromberg, BOEM Office of Renewable Energy Programs, 381 Elden Street, HM 1328, Herndon, Virginia 20170, (703) 787-1320 or
This PSN is published pursuant to subsection 8(p) of the OCS Lands Act (43 U.S.C. 1337(p)) (the Act), as amended by section 388 of the Energy Policy Act of 2005 (EPAct), and the implementing regulations at 30 CFR Part 585, including 30 CFR 585.211 and 30 CFR 585.216.
On November 2, 2012, BOEM published a Notice of Availability (NOA) for the
Based on the public comments received in response to the EA, the conclusion of required consultations, and public outreach and information meetings, BOEM decided to make certain revisions to the EA originally published in November 2012. As a result of the analysis in the revised EA, BOEM is issuing a Finding of No Significant Impact (FONSI). The
Additional environmental reviews will be conducted upon receipt of a successful Lessee's proposed project-specific plans, such as a SAP or Construction and Operations Plan (COP).
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BOEM, through its contractor, will hold an auction as described in this notice. The auction will take place no sooner than 30 days following publication of the FSN in the
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BOEM has proposed these financial terms and conditions in this PSN and in the four commercial leases that accompany the PSN. However, BOEM recognizes that there may be concerns related to the potential costs associated with development of commercial wind energy projects in the water depths associated with the Massachusetts WEA. Therefore, BOEM is requesting comments in order to evaluate whether the following modifications to said terms and conditions are warranted: (1) Reduction of the annual rent to less than $3 per acre; (2) reduction of the annual rent for any project easement associated with the lease; and (3) reduction of the annual operating fee rate to less than 0.02 (i.e., 2%). If a potential bidder is interested in obtaining a lease that
The first year's rent payment of $3 per acre for the entire Lease Area (LA) is due within 45 days of the date the Lessee receives the lease for execution. Thereafter, annual rent payments are due on the anniversary of the Effective Date of the lease, i.e., the Lease Anniversary. Once the first commercial operations under the lease begin, rent will be charged on the remaining part of the lease not authorized for commercial operations, i.e., not generating electricity. However, instead of geographically dividing the LA into acreage that is “generating” and acreage that is “non-generating,” the fraction of the lease accruing rent is based on the fraction of the total nameplate capacity of the project that is not yet in operation. The fraction is the nameplate capacity (as defined herein), which is not yet authorized for commercial operations at the time payment is due, divided by the maximum nameplate capacity after full installation of the project, as defined in the COP. This fraction is then multiplied by the amount of rent that would be due for the Lessee's entire LA at the rental rate of $3 per acre, to obtain the annual rent due for a given year.
For example, for a lease the size of 742,978 acres (the size of the entire Massachusetts WEA), the amount of rent payment would be $2,228,934 per year if no portion of the leased area is authorized for commercial operations. If 500 megawatts (MW) of a project's nameplate capacity is operating (or authorized for operation), and its most recent approved COP specifies a maximum nameplate capacity of 1000 MW, the rent payment would be $1,114,467. For the above example, this would be calculated as follows: 500 MW/1000 MW × ($3/acre × 742,978 acres) = $1,114,467.
The Lessee also must pay rent for any project easement associated with the lease commencing on the date that BOEM approves the COP (or COP modification) that describes the project easement. Annual rent for a project easement 200-feet wide and centered on the transmission cable is $70.00 per statute mile. For any additional acreage required, the Lessee must also pay the greater of $5.00 per acre per year or $450.00 per year.
BOEM is requesting comments and supporting information to determine whether it should modify rent payments for the commercial leases to be executed for the Massachusetts WEA.
For the purposes of calculating the initial annual proposed operating fee payment, an operating fee rate is applied to a proxy for the wholesale market value of the electricity expected to be generated from the project during its first twelve months of operations. This initial payment is prorated to reflect the period between the commencement of commercial operations and the Lease Anniversary. The initial annual operating fee payment is due within 45 days of the commencement of commercial operations. Thereafter, subsequent annual operating fee payments are due on or before each Lease Anniversary. The subsequent annual operating fee payments are calculated by multiplying an operating fee rate by the imputed wholesale market value of the projected annual electric power production. For the purposes of this calculation, the imputed market value is the product of the project's annual nameplate capacity, the total number of hours in the year (8,760), a capacity utilization factor, and the annual average price of electricity derived from a historical regional wholesale power price index. For example, an annual operating fee for a 100 MW wind facility operating at 40% capacity with a regional wholesale power price of $40/MWh under an operating fee rate of 0.02 (i.e., 2%) would be calculated as follows: Annual operating fee = 100 MW × 8,670 hours/year × 0.4 × $40/MWh power price × 0.02.
The capacity factor for the year in which the Commercial Operation Date occurs and for the first six full years of commercial operations on the lease is set to 0.4 (i.e., 40%) to allow for one year of installation and testing followed by five years at full availability. At the end of the sixth year, the capacity factor may be adjusted to reflect the performance over the previous five years based upon the actual metered electricity generation at the delivery point to the electrical grid. Similar adjustments to the capacity factor may be made once every five years thereafter. The maximum change in the capacity factor from one period to the next will be limited to plus or minus 10 percent of the previous period's value.
Within 10 business days after receiving the lease copies, the provisional winner must provide an initial lease-specific bond or other approved means of meeting the Lessor's
The financial terms can be found in Addendum “B” of the proposed leases, which BOEM has made available with this notice on its Web site at:
Following the auction, bid deposits will be applied against any bonus bids or other obligations owed to BOEM. If the bid deposit exceeds a bidder's total financial obligation, the balance of the bid deposit will be refunded to the bidder. BOEM will refund bid deposits to unsuccessful bidders.
A map of the four proposed LAs and a table of the boundary coordinates in X, Y (eastings, northings) UTM Zone 18, NAD83 Datum and geographic X, Y (longitude, latitude), NAD83 Datum can be found at the following URL:
A large scale map of these areas showing boundaries of the area with numbered blocks is available from BOEM at the following address: Bureau of Ocean Energy Management, Office of Renewable Energy Programs, 381 Elden Street, HM 1328, Herndon, Virginia 20170, Phone: (703) 787-1320, Fax: (703) 787-1708.
BOEM commissioned the Department of Energy's National Renewable Energy Laboratory (NREL) to develop a methodology for delineation of the Massachusetts WEA into non-overlapping LAs for BOEM to consider for inclusion in this PSN. NREL obtained relevant information related to the Massachusetts WEA, such as bathymetry and wind speed information, and calculated gross capacity and annual energy production using different wind turbine generator spacing and layout scenarios. BOEM provided NREL with the industry nominations received in response to previously published notices associated with BOEM's Massachusetts offshore wind planning process to inform this analysis. Additionally, NREL conducted wake effects analysis with the goal of minimizing wake effects between LAs. NREL also provided draft reports and presented the draft and final findings to the BOEM Massachusetts Intergovernmental Renewable Energy Task Force. NREL's final report, entitled “Assessment of Offshore Wind Energy Leasing Areas for the BOEM Massachusetts Wind Energy Area,” was released on December 20, 2013, and is available on BOEM's Web site at:
In the final report, NREL presented three alternatives for BOEM's consideration for delineation of the Massachusetts WEA: Alternative 1 consists of four LAs divided along diagonal lines parallel to the prevailing wind direction (southwest to northeast)
In this PSN, BOEM is proposing to auction the Massachusetts WEA as four leasing areas as described in Alternative 1 of NREL's final report. However, potential bidders should note that BOEM may choose to offer for sale the LAs outlined in Alternative 2 or 3 of NREL's final report, after considering the comments submitted in response to the PSN. BOEM will announce its final decision as to the Massachusetts WEA leasing areas that will be offered for sale in the FSN.
• Addendum “A” (Description of Leased Area and Lease Activities);
• Addendum “B” (Lease Term and Financial Schedule);
• Addendum “C” (Lease Specific Terms, Conditions, and Stipulations);
• Addendum “D” (Project Easement);
• Addendum “E” (Rent Schedule);
• Appendix A to Addendum “C”: (Incident Report: Protected Species Injury or Mortality); and
• Appendix B to Addendum “C”: (Required Data Elements for Protected Species Observer Reports).
Addenda “A”, “B”, and “C” provide detailed descriptions of lease terms and conditions. Addenda “D” and “E” will be completed at the time of COP approval.
After considering comments on the PSN and proposed leases, BOEM will publish final lease terms and conditions in the FSN.
Pursuant to 30 CFR 585.601, the leaseholder must submit a SAP within 12 months of lease issuance. If the leaseholder intends to continue its commercial lease with an operations term, the leaseholder must submit a COP at least 6 months before the end of the site assessment term.
The commercial wind leasing areas proposed for sale in this PSN are among the largest delineated by BOEM to date. In light of this, BOEM is soliciting comments on the concept of executing commercial leases for the Massachusetts WEA with an operations term greater than the 25 years proposed in this PSN. If a potential bidder is interested in obtaining a lease that reflects the adjustments to the operations term described above, then that party should submit their comments and qualifications package during the comment period of this PSN. The decision whether to execute leases with an operations term greater than 25 years will be made in accordance with 30 CFR 585.235.
Guidance and examples of the appropriate documentation demonstrating the required legal qualifications can be found in Chapter 2 and Appendix B of
Bidders must submit documentation necessary to demonstrate their legal, technical, and financial qualifications to BOEM in both paper and electronic formats. BOEM considers an Adobe PDF file stored on a compact disc (CD) to be an acceptable format for submitting an electronic copy. In their qualification materials, bidders must provide a general description of the project that they would like to construct on the LA sought in this sale, including estimates of the project area and total nameplate capacity of the proposed facilities.
Please note that it may take a number of weeks for bidders to establish their legal, technical, and financial qualifications. BOEM advises potential bidders planning to participate in a sale to establish their qualifications promptly. It is not uncommon for BOEM to request additional materials establishing qualifications following an initial review of the qualifications package. Any potential bidder whose qualification package is incomplete at the time the FSN for this sale is published in the
Finally, potentially interested parties should note that BOEM may decide to move forward with one of the other two LA alternatives outlined in NREL's final report, based upon comments received in response to this PSN and other relevant information provided to the Bureau. Potentially interested parties should also note that BOEM is considering (1) lowering certain payment requirements, and (2) lengthening the operations terms associated with the proposed commercial leases, as described earlier in this PSN. If a potential bidder is interested in obtaining a lease included in any of the the leasing alternatives outlined in NREL's final report and/or is interested in obtaining a lease with the adjustments to the financial terms and
For the sale of Lease OCS-A 0500, Lease OCS-A 0501, Lease OCS-A 0502, and Lease OCS-A 0503, BOEM will use a multiple-factor auction format with a multiple-factor bidding system. Under this system, BOEM may consider a combination of monetary and non-monetary factors, or “variables,” in determining the outcome of the auction. BOEM will appoint a panel of three BOEM employees for the purposes of reviewing the non-monetary packages and verifying the results of the lease sale. BOEM reserves the right to change the composition of this panel prior to the date of the lease sale. The panel will determine whether any bidder has earned a non-monetary credit to be used during the auction (i.e., if a bidder holds a Community Benefits Agreement (CBA) or a Power Purchase Agreement (PPA)), and if one or more bidders have earned such a credit, the percentage that the credit will be worth. The auction will balance consideration of two variables: (1) A cash bid, and (2) a non-monetary credit. In sum, these two variables comprise the multi-factor bid or “As-Bid” auction price. A bidder's As-Bid price, which is the sum of its cash bid and any credit portion earned, will either meet BOEM's asking price or be reflected in the bidder's own Intra-Round Bid price subject to certain conditions, as described more fully herein. A multiple-factor auction, wherein both monetary and nonmonetary bid variables are considered, is provided under BOEM's regulations at 30 CFR 585.220(a)(4) and 585.221(a)(6).
Under a multiple-factor bidding format, as set forth at 30 CFR 585.220(a)(4), BOEM may consider a combination of factors as part of a bid. The regulations state that one bid proposal per bidder will be accepted, but do not further specify the procedures to be followed in the multiple-factor format. This multiple-factor format is intended to allow BOEM flexibility in administering the auction and in balancing the variables presented. The regulations leave to BOEM the determination of how to administer the multiple-factor auction format to ensure the receipt of a fair return under the Act, 43 U.S.C. 1337(p)(2)(A).
BOEM's regulations at 30 CFR 585.220(a)(4) allow for a multi-round auction in which each bidder may submit only one proposal per LA or for a set of LAs in each round of the auction. The auction will be conducted in a series of rounds. At the start of each round, BOEM will state an asking price for each LA offered. The asking price for a bid on more than one LA is the sum of the asking prices for each LA in the bid. Each bidder will indicate whether it is willing to meet the asking price for one or more LAs. A bid submitted at the full asking price for one or more LAs in a particular round is referred to as a “live bid.” A bidder must submit a live bid for at least one of the LAs in each round to participate in the next round of the auction. As long as there is at least one LA that is included in two or more live bids, the auction continues, and the next round is held.
A bidder's As-Bid price must meet the asking price in order for it to be considered a live bid. A bidder may meet the asking price by submitting a monetary bid equal to the asking price or, if it has earned a credit, by submitting a multiple-factor bid—that is, a live bid that consists of a monetary element and a non-monetary element, the sum of which equals the asking price. A multiple-factor bid would consist of the sum of a cash portion and any credit portion which the bidder has earned.
An uncontested bid is a live bid that does not overlap with other live bids in that round. For example, a bid for two LAs is considered contested if any LA included in that bid is included in another bid—a bid cannot be “partially uncontested.” An uncontested bid represents the only apparent interest in that bid's LA(s) at the asking price for that round. If a bidder submits an uncontested bid consisting of one or more LAs, and the auction continues for another round, BOEM automatically carries that same live bid forward as a live bid into the next round, and BOEM's asking price for the LA(s) contained in the uncontested bid would remain unchanged from the previous round. If the price on any LAs in that bid rises later in the auction because another bidder places a live bid on one or more of those LAs, BOEM will stop automatically carrying forward the previously uncontested bid. Once the asking price(s) goes up, the bidder that placed the previously carried-forward bid is free to bid on either LA at the new asking price(s).
Following each round in which a LA is contained in more than one live bid, BOEM will raise the asking price for that LA by an increment determined by BOEM. The auction concludes when each LA is included in no more than one live bid. The series of rounds and the rising asking prices set by BOEM will facilitate consideration of the first variable—the cash portion of the bid.
The second variable—a credit of 5% of a monetary bid for holding a CBA or a credit of up to 25% of a monetary bid for holding a PPA—will be applied throughout the auction rounds as a form of imputed payment against the asking price for the highest priced LA in a bidder's multiple-factor bid. This credit serves to supplement the amount of a cash bid proposal made by a particular bidder in each round. In the case of a bidder holding a credit and bidding on more than one LA, the credit will be applied only on the LA with the highest asking price. More details on the non-monetary factors are found in the “Credit Factors” section herein.
The panel will evaluate non-monetary packages consisting of any CBA or PPA to determine whether it meets the criteria provided in the FSN, and therefore whether it will qualify for a credit for its holder. It is possible that the panel could determine that no bidder qualifies for a non-monetary credit during the auction, in which case the auction would otherwise proceed as described in the FSN. The panel will determine the winning bids for each LA on the basis of the procedures described in the FSN.
Each bidder is allowed to submit a live bid for any number of LAs based on its “eligibility” at the opening of each round. A bidder's eligibility is either four, three, two, one, or zero LAs, and it corresponds to the maximum number of LAs that a bidder may include in a live bid during a single round of the auction. A bidder's initial eligibility is determined based on the amount of the bid deposit submitted by the bidder prior to the auction. To be eligible to offer a bid on one LA at the start of the auction, a bidder must submit a bid deposit of $450,000. To be eligible to offer a bid on two LAs in the first round of the auction, the bidder must submit a bid deposit of $900,000; for three LAs, the bid deposit is $1,350,000; for four LAs, the bid deposit is $1,800,000. A bidder's bid deposit will be used by BOEM as a down payment on any monetary obligations incurred by the bidder should it be awarded a lease.
As the auction proceeds, a bidder's eligibility is determined by the number
In the first round of the auction, bidders have the following options:
A bidder with an initial eligibility of one (that is, a bidder who submitted a bid deposit of $450,000) may:
• Submit a live bid on any of the four LAs, or
• Submit nothing, and drop out of the auction.
• Submit a live bid for any number of LAs up to its bid eligibility, or
• Submit nothing, and drop out of the auction.
There is no requirement that the LAs contained in a live bid be contiguous. A bidder who has included multiple LAs in a live bid can include any combination of LAs up to the bidder's bid eligibility. Before each subsequent round of the auction, BOEM will raise the asking price for any LA that was contained in more than one live bid in the previous round. BOEM will not raise the asking price for a LA that was in only one or no live bids in the previous round.
Asking price increments will be determined by BOEM, in its sole discretion. BOEM will base asking price increments on a number of factors, including:
• Making the increments sufficiently large that the auction will not take an unduly long time to conclude; and
• Decreasing the increments as the asking price of a LA nears its apparent final price.
BOEM reserves the right during the auction to increase or decrease increments if it determines, in its sole discretion, that a different increment is warranted to enhance the efficiency of the auction process. Asking prices for the LAs included in multiple live bids in the previous round will be raised and rounded to the nearest whole dollar amount to obtain the asking prices in the current round.
A bidder must submit a live bid in each round of the auction (or have an uncontested live bid automatically carried forward by BOEM) for it to remain active and continue bidding in future rounds. All of the live bids submitted in any round of the auction will be preserved and considered binding until determination of the winning bids is made. Therefore, the bidders are responsible for payment of the bids they submit and can be held accountable for up to the maximum amount of those bids determined to be winning bids during the final award procedures.
Between rounds, BOEM will release the following information to the bidders:
• The level of demand for each LA in the previous round of the auction (i.e., the number of live bids that included the LA); and
• The asking price for each LA in the upcoming round of the auction.
In any subsequent round of the auction, if a bidder's previous round bid was uncontested, and the auction continues for another round, then BOEM will automatically carry forward that bid as a live bid in the next round. A bidder whose bid is being carried forward will not have an opportunity to modify or drop its bid until some other bidder submits a live bid that overlaps with the LA(s) in the carried forward bid. In particular, for rounds in which a bidder finds its uncontested bid is carried forward, the bidder will be unable to do the following:
• Switch to any other LAs;
• Submit an Intra-Round Bid (see herein for discussion of Intra-Round Bids); or
• Drop out of the auction.
A bidder may be bound by that bid or, indeed, by any other bid which BOEM determines is a winning bid in the award stage. Hence, a bidder cannot drop an uncontested bid. In no scenario can a bidder be relieved of any of its bids from previous or future rounds until a determination is made in the award stage about the LAs won by the bidder.
Except when a bidder's bid is being carried forward by BOEM (i.e., an uncontested bid), a bidder with an eligibility of one (that is, a bidder who submitted a live bid for one LA in the previous round) may:
• Submit a live bid for any of the four LAs;
• Submit an Intra-Round Bid for the same LA for which the bidder submitted a live in the previous round, and exit the auction; or
• Submit nothing, and drop out of the auction.
A bidder with an eligibility of two or more (that is, a bidder who submitted a live bid for two or more LAs in the previous round) may:
• Submit a live bid for any number of LAs up to its eligibility;
• Submit an Intra-Round Bid for the specific combination of LAs in that bidder's previous-round bid, and a live bid for any number of LAs fewer than the number of LAs in that bidder's previous-round bid;
• Submit an Intra-Round Bid for the specific combination of LAs in that bidder's previous-round bid, no live bids, and exit the auction; or
• Submit nothing, and drop out of the auction.
Subsequent auction rounds occur in this sale as long as one of the four LAs is contested. The auction concludes at the end of the round in which none of the LAs is included in the live bid of more than one bidder, i.e., all live bids are uncontested.
All asking prices and asking price increments will be determined by the BOEM Auction Manager, as described previously in this PSN. Intra-Round Bidding allows bidders to more precisely express the maximum price they are willing to offer for a single LA or for a combination of LAs while also minimizing the chance of ties. An Intra-Round Bid must consist of a single offer price for exactly the same LA(s) included in the bidder's live bid in the previous round.
When submitting an Intra-Round Bid, the bidder is indicating that it is not willing to meet the current round's asking price, but it is willing to pay more than the previous round's asking price. In particular, in an Intra-Round Bid, the bidder specifies the maximum (higher than the previous round's asking price and less than the current round's asking price) that it is willing to offer for the specific LA(s) in its previous round's live bid.
Although an Intra-Round Bid is not a live bid, in the round in which a valid Intra-Round Bid is submitted for any number of LAs, the bidder's eligibility for a live bid in that same round and future rounds is permanently reduced from including the amount of LAs in the previous round to one less than that. In other words, once an Intra-Round Bid is submitted, the bidder will never again have the opportunity to submit a live bid on as many LAs as it has bid in previous rounds.
BOEM will not consider Intra-Round Bids for the purpose of determining whether to increase the asking price for a particular LA or to end the auction. Also, BOEM will not count nor share with bidders between rounds the number of Intra-Round Bids received for each LA.
All of the Intra-Round Bids submitted during the auction will be preserved, and may be determined to be winning bids. Therefore, bidders are responsible for payment of the bids they submit and may be held accountable for up to the maximum amount of any Intra-Round Bids or live bids determined to be winning bids during the final award procedures.
After the bidding ends, BOEM will determine the provisionally winning bids in accordance with the process described in this section. This process consists of two stages: Stage 1 and Stage 2, which are described herein. Once the auction itself ends, nothing further is required of bidders within or between Stages 1 and 2. In practice, the stages of the process will take place as part of the solution algorithm for analyzing the monetary and credit portion of the bids, determining provisional winners, finding the LAs won by the provisional winners, and calculating the applicable bid prices to be paid by the winners for the LAs they won. This evaluation will be reviewed, checked, and validated by the panel. The determination of provisional winners, in both stages, will be based on the two auction variables, as well as on a bidder's adherence to the rules of the auction, and the absence of conduct detrimental to the integrity of the competitive auction.
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Live bids submitted in the final round of the auction are Qualified Bids. In Stage 1, a bidder with a Qualified Bid is provisionally assured of winning the LA(s) included in its final round bid, regardless of any other prior-to-final round live bids or Intra-Round Bids in any round. If all LAs are awarded to bidders in Stage 1, the second award stage is not necessary. If any LA received a bid but was not awarded in Stage 1 because no live bids were received in the final round of the auction, BOEM will proceed to Stage 2 to award the leases.
Following the auction, all winning bidders must pay the price associated with their winning bids, which may consist of cash and non-monetary credits or just cash.
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All bids are either Qualified Bids or Contingent Bids. Contingent bids are all live bids received before the final round, and any Intra-Round Bids received during the auction. In Stage 2, BOEM will consider Contingent Bids to see if the non-awarded LA(s) can be awarded without interfering with Stage 1 awards. BOEM will award leases in Stage 2 to the bid(s) that maximize(s) the total As-Bid prices.
Any Contingent Bids that conflict with Qualified Bids will not be considered. There is one notable exception to this rule. This exception allows BOEM to accept a Contingent Bid for a combination of LAs notwithstanding the existence of a Qualified Bid, provided the acceptance of the Contingent Bid for these LAs results in higher overall As-Bid prices than acceptance of only the Qualified Bid. In this scenario, a bidder would be awarded the LAs included in the Contingent Bid and would be required to pay its live bid price or its Intra-Round Bid price for those LAs included in the Contingent Bid.
This exception represents the only situation in which BOEM will consider for award a Contingent Bid which overlaps a Qualified Bid. In contrast, there is no situation in which one bidder's Contingent Bid will be considered for award if it overlaps with any LA that is included in another bidder's Qualified Bid.
Under certain circumstances, different combinations of Contingent Bids may result in the same total As-Bid price. In such cases, BOEM will resolve the resulting tie with a random drawing.
In the event a bidder submits a bid for a LA that the panel and BOEM determine to be a winning bid, the bidder will be expected to sign the applicable lease documents in a timely manner and submit the full cash payment due, pursuant to 30 CFR 585.224. If a bidder fails to timely sign and pay for the lease, then BOEM will not issue the lease to that bidder, and the bidder will forfeit its bid deposit. BOEM may consider failure of a bidder to timely pay the full amount due an indication that the bidder is no longer financially qualified to participate in other lease sales under BOEM's regulations at 30 CFR 585.106 and 585.107.
Shortly before the auction, BOEM will convene a panel (as provided in BOEM's regulations, discussed above) to evaluate bidders' non-monetary packages to determine whether and to what extent each bidder is eligible for a non-monetary credit applicable to the As-Bid auction price for one of the LAs in each round of the auction, as described herein. In order to receive a credit for a PPA or a CBA, a bidder must be legally, technically and financially eligible to acquire a commercial OCS wind lease, and must not be affiliated with any other bidding entity also seeking credit for the same PPA or CBA.
The percentage credit that will be applicable to each bidder throughout the auction and award process is determined based on the panel's evaluation of required documentation submitted by the bidders as of the deadline specified in the FSN. Bidders will be informed by email before the monetary auction about the percentage credit applicable to their bids. A bidder may not receive more than one bid credit, and the bid credit will be applicable to only one LA. Any non-monetary credit would only be applicable to the highest priced LA in a bid for multiple LAs. For an Intra-Round Bid containing multiple LAs, the highest priced LA will be determined using the previous round's asking prices. In each round, the auction system will display to each bidder information showing how their As-Bid auction prices are affected by the credit imputed to their bid to determine their net monetary payment due to BOEM, should their bids prevail as winning bids in the award stages. Application of the credit percentage to the appropriate As-Bid auction price will be rounded to the nearest whole dollar amount.
The bidder's credit percentage is limited to the greater of 5% for a CBA or up to 25% for a PPA. This credit percentage will be applied to the highest priced LA related to the bidder's latest live bid or Intra-Round Bid. In the case of an Intra-Round Bid for multiple LAs, the credit will apply only to the highest-priced LA, but the applicable price for calculating the credit will be based on the previous round's asking prices, not on any additional amount above the previous round's asking prices as reflected in the incremental amount associated with its Intra-Round Bid.
The panel will review the non-monetary package submitted by each bidder and, based on the criteria provided in the FSN for a CBA and PPA, determine whether bidders have established that they are qualified to receive a credit, and the percentage at which that credit will apply. If the panel determines that no bidder has qualified for a non-monetary factor, the auction will proceed with each bidder registered with no imputed credit.
The definitions herein will apply to the factors for which bidders may earn a credit.
In order for a non-monetary package to qualify for a 5% credit in this auction, the BOEM-appointed panel must answer yes to the following questions:
1. Is there a legally binding contract?
2. Is the contract between:
a. A bidder; and
b. One or more community-based organizations (CBO)?
3. Has the bidder committed to provide specified community benefits?
4. Has the CBO committed in specific ways to support the project in the governmental approval process?
A community-based organization (CBO) is defined as: A legally incorporated organization whose membership includes residents or property owners of a community within the potentially affected region, the local government of the community, or an entity created or managed by the local government(s) of the community or communities.
Bidders seeking non-monetary credit for a CBA will be required to submit the CBA as part of their non-monetary package by the date specified in the FSN. In addition, bidders must include a description of how the CBA meets the requirements outlined in the FSN. For protection of confidential business information, please see the section entitled “Protection of Privileged or Confidential Information” in this notice.
(i) A complete description of the proposed project;
(ii) Identification of both the electricity Generator and Buyer that will enter into a long term contract;
(iii) A time line for permitting, licensing, and construction;
(iv) Pricing projected under the long term contract being sought, including prices for all market products that would be sold under the proposed long term contract;
(v) A schedule of quantities of each product to be delivered and projected electrical energy production profiles;
(vi) The term for the long-term contract;
(vii) Citations to all filings related to the PPA that have been made with state and Federal agencies, and identification of all such filings that are necessary to be made; and
(viii) Copies of or citations to interconnection filings related to the PPA.
If the panel determines a bidder has executed a PPA for at least 250 MW, it will be eligible for the entire 25% credit. If the panel determines a bidder has executed a PPA for an amount less than 250 MW, the bidder may still be eligible for a non-monetary credit proportional to the PPA's fraction of 250 MW. The smaller percentage for a partial credit will be calculated according to the formula below:
Where:
• Partial Credit = Percent credit for which a smaller PPA is eligible.
• Full PPA = 250 MW
• Full Credit = 25%
• Partial PPA = amount (less than 250 MW) of power under contract
All bidders seeking a non-monetary auction credit will be required to submit a non-monetary auction package prior to the auction. Instructions and deadlines for submittal will be provided in the FSN. If a bidder does not submit a non-monetary package by the date specified in the FSN, then BOEM will assume that bidder is not seeking a non-monetary auction credit and the panel will not consider that bidder for a non-monetary auction credit.
Prior to the auction, the Auction Manager will send several bidder authentication packages to each bidder shortly after BOEM has processed the BFFs. One package will contain tokens for each authorized individual. Tokens are digital authentication devices. The tokens will be mailed to the Primary Point of Contact indicated on the BFF. This individual is responsible for distributing the tokens to the individuals authorized to bid for that company. Bidders are to ensure that each token is returned within three business days following the auction. An addressed, stamped envelope will be provided to facilitate this process. In the event that a bidder fails to submit a BFF or a bid deposit, or does not participate in the auction, BOEM will de-activate that bidder's token and login information, and the bidder will be asked to return its tokens.
The second package contains login credentials for authorized bidders. The login credentials will be mailed to the address provided in the BFF for each authorized individual. Bidders can confirm these addresses by calling (703) 787-1320. This package will contain user login information and instructions for accessing the Auction System Technical Supplement and Alternative Bidding Form. The login information,
Specific information regarding when the bidders can enter the auction system and the auction start time will be provided in the FSN. Additional information will be made available in an Auction System Technical Supplement, which will be posted on BOEM's Web site prior to the auction.
BOEM and the auction contractors will use the auction platform messaging service to keep bidders informed on issues of interest during the auction. For example, BOEM may change the schedule at any time, including during the auction. If BOEM changes the schedule during the auction, it will use the messaging feature to notify bidders that a revision has been made, and direct bidders to the relevant page. BOEM will also use the messaging system for other changes and items of particular note during the auction. The auction schedule and asking price increments are in BOEM's discretion, and are subject to change at any time before or during the auction.
During the auction, bidders may place bids at any time during the round. At the top of the bidding page, a countdown clock will show how much time remains in the round. Bidders have until the scheduled time to place bids. Bidders should place bids according to the procedures described in the Auction System Technical Supplement, and as practiced at the Mock Auction. No information about the round is available until the round has closed and results have been posted, so there should be no strategic advantage to placing bids early or late in the round.
Any bidder who is unable to place a bid using the online auction and would be interested in placing a bid using the Alternate Bidding Procedures must call BOEM/the BOEM Auction Manager at the help desk number that is listed in the Auction System Technical Supplement before the end of the round. BOEM will authenticate the caller to ensure he/she is authorized to bid on behalf of the company. The bidder must explain to the BOEM Auction Manager the reasons for which he/she is forced to place a bid using the Alternate Bidding Procedure. At that time, BOEM may, in its sole discretion, permit or refuse to accept a request for the placement of a bid using the Alternative Bidding Procedure.
The Alternative Bidding Procedure enables a bidder who is having difficulties accessing the Internet to submit its bid via an Alternative Bidding Form that must be faxed to the Auction Manager. If the bidder has not placed a bid, but calls BOEM before the end of the round and notifies BOEM that it is preparing a bid using the Alternate Bidding Procedure, and submits the Alternate Bidding Form by fax before the round ends, BOEM will likely accept the bid, though acceptance or rejection of the bid is within BOEM's sole discretion. If the bidder calls during the round, but does not submit the bid until after the round ends (but before the round is posted), BOEM may or may not accept the bid, in part based on how much time remains in the recess. Bidders are strongly encouraged to submit the Alternative Bidding Form before the round ends. If the bidder calls during the recess following the round, but before the previous round's results have been posted, BOEM will likely reject its bid, even if it has otherwise complied with all of BOEM's Alternate Bidding Procedures. If the bidder calls to enter a bid after results have been posted, BOEM will reject the bid.
Except for bidders who have uncontested bids in the current round, failure to place a bid during a round will be interpreted as dropping out of the auction. Bids in all rounds are preserved for consideration in Stage 2 of the award process. Bidders are held accountable for all bids placed during the auction. This is true if they continued bidding in the last round, if they placed an Intra-Round Bid in an earlier round, or if they stopped bidding during the auction.
1. Execute the lease on the bidder's behalf;
2. File financial assurance as required under 30 CFR 585.515-537; and
3. Pay by electronic funds transfer (EFT) the balance of the bonus bid (bid amount less the bid deposit). BOEM requires bidders to use EFT procedures (not to include
If a winning bidder does not meet these three requirements within 10 business days of receiving the lease copies as described herein, or if a winning bidder otherwise fails to comply with applicable regulations or the terms of the FSN, the winning bidder will forfeit its bid deposit. BOEM may extend this 10 business-day time period if it determines the delay was caused by events beyond the winning bidder's control.
In the event that the provisional winner does not execute and return the leases according to the instructions in the FSN, BOEM reserves the right to reconvene the panel to determine whether it is possible to identify a bid that would have won in the absence of the bid previously determined to be the winning bid. In the event that a new winning bid is selected by the panel, BOEM will follow the procedures in this section for the new winner(s).
BOEM will not execute a lease until (1) the three requirements above have been satisfied, (2) BOEM has accepted the winning bidder's financial assurance, and (3) BOEM has processed the winning bidder's payment. The winning bidder may meet financial assurance requirements by posting a surety bond or by setting up an escrow account with a trust agreement giving BOEM the right to withdraw the money held in the account on demand. BOEM may accept other forms of financial assurance on a case-by-case basis in accordance with its regulations. BOEM encourages provisionally winning bidders to discuss the financial assurance requirement with BOEM as soon as possible after the auction has concluded.
Within 45 days of the date that the winning bidder receives the lease copies, the winning bidder must pay the first year's rent using the
In accordance with the Act at 43 U.S.C. 1337(c), following the auction, and before the acceptance of bids and the issuance of leases, BOEM will “allow the Attorney General, in consultation with the Federal Trade Commission, thirty days to review the results of the lease sale.” If a bidder is found to have engaged in anti-competitive behavior or otherwise violated BOEM's rules in connection with its participation in the competitive bidding process, BOEM may reject the high bid.
Anti-competitive behavior determinations are fact specific. However, such behavior may manifest itself in several different ways, including, but not limited to:
• An agreement, either express or tacit, among bidders to not bid in an auction, or to bid a particular price;
• An agreement among bidders not to bid for a particular LA;
• An agreement among bidders not to bid against each other; and
• Other agreements among bidders that have the effect of limiting the final auction price.
BOEM may decline to award a lease if, pursuant to the Act (43 U.S.C. 1337(c)), it is determined by the Attorney General in consultation with the Federal Trade Commission that doing so would be inconsistent with antitrust laws (e.g., heavily concentrated market, etc.).
For more information on whether specific communications or agreements could constitute a violation of Federal antitrust law, please see:
(a) If BOEM rejects your bid, BOEM will provide a written statement of the reasons and refund any money deposited with your bid, without interest.
(b) You will then be able to ask the BOEM Director for reconsideration, in writing, within 15 business days of bid rejection, under 30 CFR 585.118(c)(1). BOEM will send you a written response either affirming or reversing the rejection.
The procedures for appealing final decisions with respect to lease sales are described in 30 CFR 585.118(c).
BOEM will protect privileged or confidential information that is submitted as required by the Freedom of Information Act (FOIA). Exemption 4 of FOIA applies to trade secrets and commercial or financial information that is privileged or confidential. If you wish to protect the confidentiality of such information, clearly mark it and request that BOEM treat it as confidential. BOEM will not disclose such information, except as required by FOIA. Please label privileged or confidential information “Contains Confidential Information” and consider submitting such information as a separate attachment.
However, BOEM will not treat as confidential any aggregate summaries of such information or comments not containing such information. Additionally, BOEM may not treat as confidential the legal title of the commenting entity (e.g., the name of a company). Information that is not labeled as privileged or confidential will be regarded by BOEM as suitable for public release.
BOEM is required, after consultation with the Secretary of the Department of the Interior, to withhold the location, character, or ownership of historic resources if it determines that disclosure may, among other things, cause a significant invasion of privacy, risk harm to the historic resources or impede the use of a traditional religious site by practitioners. Tribal entities and other interested parties should designate information that they wish to be held as confidential and provide the reasons why BOEM should do so.
Bureau of Ocean Energy Management (BOEM), Interior.
Notice of the Availability of a Revised Environmental Assessment (EA) and a Finding of No Significant Impact (FONSI).
BOEM has prepared a revised EA considering the reasonably foreseeable environmental and socioeconomic effects of issuing renewable energy leases and lessees' subsequent site characterization
In accordance with the requirements of the National Environmental Policy Act (NEPA) and the Council on Environmental Quality's (CEQ) regulations implementing NEPA at 40 CFR 1500-1508, BOEM issued a FONSI supported by the analysis in the revised EA. The FONSI concluded that the reasonably foreseeable environmental impacts associated with the proposed action and alternatives, as set forth in the EA, would not significantly impact the quality of the human environment; therefore, the preparation of an Environmental Impact Statement (EIS) is not required.
This notice is published pursuant to 43 CFR 46.305.
Michelle Morin, BOEM Office of Renewable Energy Programs, 381 Elden Street, HM 1328, Herndon, Virginia 20170-4817, (703) 787-1340 or
On November 2, 2012, BOEM published a Notice of Availability (NOA) of an EA, requesting public comment on alternatives considered in that 2012 EA. In addition, comments were requested on measures to mitigate impacts to environmental resources and socioeconomic conditions that could potentially occur in the MA WEA and surrounding areas as a result of leasing, site characterization, and site assessment activities in those areas (77 FR 66185).
The 2012 EA considered the impacts that could result from leasing the entire MA WEA and BOEM's approval of site assessment plans within that area. Comments received in response to the 2012 NOA can be viewed at:
Based on comments received on the 2012 EA, and results of required consultations (e.g., Endangered Species Act), BOEM revised the 2012 EA. BOEM will use this revised EA to inform decisions to issue leases in the MA WEA, and to subsequently approve Site Assessment Plans (SAPs) on those leases. BOEM may issue one or more commercial wind energy leases in the MA WEA. The competitive lease process is set forth at 30 CFR 585.210-585.225.
A commercial lease gives the lessee the exclusive right to seek BOEM approval for the development of the leasehold. The lease does not grant the lessee the right to construct any facilities; rather, the lease grants the lessee the right to use the leased area to develop its plans, which BOEM must approve before the lessee may proceed to the next stage of the process.
If a lessee is prepared to propose a wind energy generation facility on its lease, it would submit a Construction and Operations Plan (COP). BOEM then would prepare a separate site- and project-specific NEPA analysis of the proposed project. This analysis would likely take the form of an EIS in which BOEM would evaluate the reasonably foreseeable environmental and socioeconomic consequences of the proposed project. The EIS would provide the public and Federal officials with comprehensive information regarding the reasonably foreseeable environmental impacts of the proposed project and would inform BOEM's decision to approve, approve with modification, or disapprove a lessee's COP pursuant to 30 CFR 585.628. This process would include additional opportunities for public involvement pursuant to NEPA.
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the scheduling of the final phase of antidumping duty investigation nos. 731-TA-1229-1230 (Final) under section 735(b) of the Tariff Act of 1930 (19 U.S.C. 1673d(b)) (the Act) to determine whether an industry in the United States is materially injured or threatened with material injury, or the establishment of an industry in the United States is materially retarded, by reason of less-than-fair-value imports from China and Indonesia of monosodium glutamate, provided for in subheading 2922.42.10 of the Harmonized Tariff Schedule of the United States.
For further information concerning the conduct of this phase of the investigations, hearing procedures, and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A and C (19 CFR part 207).
Amy Sherman (202-205-3289), Office of Investigations, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special
Additional written submissions to the Commission, including requests pursuant to section 201.12 of the Commission's rules, shall not be accepted unless good cause is shown for accepting such submissions, or unless the submission is pursuant to a specific request by a Commissioner or Commission staff.
In accordance with sections 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to the investigations must be served on all other parties to the investigations (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These investigations are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.21 of the Commission's rules.
By order of the Commission.
United States International Trade Commission.
Notice.
The Commission hereby gives notice of the scheduling of an expedited review pursuant to section 751(c)(3) of the Tariff Act of 1930 (19 U.S.C. 1675(c)(3)) (the Act) to determine whether revocation of the antidumping duty order on steel threaded rod from China would be likely to lead to continuation or recurrence of material injury within a reasonably foreseeable
Fred Ruggles (202-205-3187), Office of Investigations, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202-205-2000. General information concerning the Commission may also be obtained by accessing its internet server (
In accordance with sections 201.16(c) and 207.3 of the rules, each document filed by a party to the review must be served on all other parties to the review (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
This review is being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.62 of the Commission's rules.
By order of the Commission.
United States International Trade Commission.
June 24, 2014 at 11:00 a.m.
Room 101, 500 E Street SW., Washington, DC 20436, Telephone: (202) 205-2000.
Open to the public.
1. Agendas for future meetings: None.
2. Minutes.
3. Ratification List.
4. Vote in Inv. Nos. 731-TA-1210-1212 (Final) (Welded Stainless Steel Pressure Pipe from Malaysia, Thailand, and Vietnam). The Commission is currently scheduled to complete and file its determinations and views of the Commission on July 7, 2014.
5. Vote in Inv. Nos. 701-TA-454 and 731-TA-1144 (Review) (Welded Stainless Steel Pressure Pipe from China). The Commission is currently scheduled to complete and file its determinations and views of the Commission on July 7, 2014.
6. Outstanding action jackets: none.
In accordance with Commission policy, subject matter listed above, not disposed of at the scheduled meeting, may be carried over to the agenda of the following meeting.
By order of the Commission.
In accordance with Departmental Policy, 28 CFR 50.7, notice is hereby given that a proposed Consent Decree in
The proposed Consent Decree concerns a complaint filed by the United States against St. Marys Railway West LLC and Claudius R. Strickland, pursuant to Sections 402 and 404 of the Clean Water Act, 33 U.S.C. 1342 and 1344, to obtain injunctive relief from and impose civil penalties against the Defendants for violating the Clean Water Act by discharging pollutants without a permit into waters of the United States. The proposed Consent Decree resolves these allegations by requiring the Defendants to pay for mitigation and to pay a civil penalty.
The Department of Justice will accept written comments relating to the proposed Consent Decree for thirty (30) days from the date of publication of this Notice. Please address comments to Paul Cirino, Environmental Defense Section, United States Department of Justice, Post Office Box 7611, Washington, DC 20044-7611 and refer to
The proposed Consent Decree may be examined at any of the Clerk's Offices, United States District Court for the Southern District of Georgia, including the location at 601 Tebeau Street, Waycross, GA 31501. In addition, the proposed Consent Decree may be examined electronically at
Notice.
On June 30, 2014, the Department of Labor (DOL) will submit the Office of the Assistant Secretary for Administration and Management (OASAM) sponsored information collection request (ICR) titled, “Department of Labor Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery,” to the Office of Management and Budget (OMB) for review and approval for continued use, without change, in accordance with the Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501 et seq. Public comments on the ICR are invited.
The OMB will consider all written comments that agency receives on or before July 30, 2014.
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-DM, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-6881 (this is not a toll-free number); or by email:
Contact Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at
44 U.S.C. 3507(a)(1)(D).
This ICR seeks to extend PRA authority for the DOL Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery. The information collection activity will garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with the Administration's commitment to improving service delivery. By qualitative feedback we mean information that provides useful insights on perceptions and opinions, but are not statistical surveys that yield quantitative results that can be generalized to the population of study. This feedback will provide insights into customer or stakeholder perceptions, experiences, and expectations; provide an early warning of issues with service; or focus attention on areas where communication, training, or changes, in operations might improve delivery of products or services. These collections will allow for ongoing, collaborative, and actionable communications between the DOL and its customers and stakeholders. It will also allow feedback to contribute directly to the improvement of program management.
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: The target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless it is approved by the OMB under the PRA and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid Control Number.
OMB authorization for an ICR cannot be for more than three (3) years without renewal, and the current approval for this collection is scheduled to expire on June 30, 2014. The DOL seeks to extend PRA authorization for this information collection for three (3) more years, without any change to existing requirements. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. For additional substantive information about this ICR, see the related notice published in the
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the
• 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;
• 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;
• Enhance the quality, utility, and clarity of the information to be collected; and
• 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 submission of responses.
Meeting notice.
Notice is hereby given of a meeting of the Labor Advisory Committee for Trade Negotiation and Trade Policy.
July 7, 2014 10:00 a.m. to 11:30 a.m.
U.S. Department of Labor, Secretary's Conference Room, 200 Constitution Ave. NW., Washington, DC.
Anne M. Zollner, Chief, Trade Policy and Negotiations Division; Phone: (202) 693-4890.
National Aeronautics and Space Administration (NASA).
Notice of information collection.
The National Aeronautics and Space Administration, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. 3506(c)(2)(A)).
Consideration will be given to comments submitted within 30 calendar days from the date of this publication.
Interested persons are invited to submit written comments on the proposed information collection to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Officer for NASA.
Requests for additional information or copies of the information collection instrument(s) and instructions should be directed to Frances Teel, NASA PRA Clearance Officer, NASA Headquarters, 300 E Street SW., Mail Code JF000, Washington, DC 20546, (202) 358-2225.
The National Aeronautics and Space Administration (NASA) Office of Diversity and Equal Opportunity and the Office of Procurement, in accordance with Title VI of the Civil Rights Act of 1964, Title IX of the Education Amendments of 1972, Section 504 of the Rehabilitation Act of 1973, and the Age Discrimination Act of 1975, requires grant awardees to submit an assurance of non-discrimination (NASA Form1206) as part of their initial grant application package. The requirement for assurance of non-discrimination compliance associated with federally assisted programs is long standing, derives from civil rights implementing regulations, and extends to the grant recipient's sub-grantees, contractors, successors, transferees, and assignees. Grant selectees are required to submit compliance information triennially when their award period exceeds 36 consecutive months. This information collection will also be used to enable NASA to conduct post-award civil rights compliance reviews.
Electronic.
Comments are invited on: (1) Whether the proposed collection of information is necessary for the proper performance of the functions of NASA, including whether the information collected has practical utility; (2) the accuracy of
Comments submitted in response to this notice will be summarized and included in the request to OMB for approval of this information collection. They will also become a matter of public record.
Nuclear Regulatory Commission.
License renewal application; opportunity to request a hearing and to petition for leave to intervene.
The U.S. Nuclear Regulatory Commission (NRC) is considering an application for the renewal of operating license number NPF-43, which authorizes DTE Electric Company, to operate Fermi 2. The renewed license would authorize the applicant to operate Fermi 2 for an additional 20 years beyond the period specified in the current license. The current operating license for Fermi 2 (NPF-43) expires at midnight on March 20, 2025. Fermi 2 is a boiling-water reactor designed by General Electric and is located near Frenchtown Township, Monroe County, Michigan.
A request for a hearing or petition for leave to intervene must be filed by August 18, 2014.
Please refer to Docket ID NRC-2014-0109 when contacting the NRC about the availability of information regarding this document. You may access publicly-available information related to this document using any of the following methods:
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•
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Daneira Meléndez-Colón, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-3301, email:
The NRC received a license renewal application (LRA) from DTE Electric Company, dated April 24, 2014, requesting renewal of operating license number NPF-43, which authorizes DTE Electric Company to operate Fermi 2 at 3486 megawatts thermal. Fermi 2 is located in Frenchtown Township, Monroe County, Michigan. DTE Electric Company submitted the application pursuant to part 54 of Title 10 of the
The NRC staff has determined that DTE Electric Company has submitted sufficient information in accordance with 10 CFR 2.101, 54.19, 54.21, 54.22, 54.23, 51.45, and 51.53(c), to enable the staff to undertake a review of the application, and that the application is therefore complete and acceptable for docketing. The current docket number, 50-341, for operating license number NPF-43, will be retained. The determination to accept the LRA for docketing does not constitute a determination that a renewed license should be issued, and does not preclude the NRC staff from requesting additional information as the review proceeds.
Before issuance of the requested renewed license, the NRC will have made the findings required by the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. In accordance with 10 CFR 54.29, the NRC may issue a renewed license on the basis of its review if it finds that actions have been identified and have been or will be taken with respect to: (1) Managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified as requiring aging management review; and (2) time-limited aging analyses that have been identified as requiring review, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis (CLB) and that any changes made to the plant's CLB will comply with the Act and the Commission's regulations.
Additionally, in accordance with 10 CFR 51.95(c), the NRC will prepare an environmental impact statement for the renewal of the Fermi 2 operating license (NPF-43) as a supplement to the Commission's NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” dated June 2013. In considering the LRA, the Commission must find that the applicable requirements of Subpart A of 10 CFR Part 51 have been satisfied, and that matters raised under 10 CFR 2.335 have been addressed. Pursuant to 10 CFR 51.26, and as part of the environmental scoping process, the staff intends to hold public scoping meetings. Detailed information regarding the environmental scoping meetings will be the subject of a separate
Within 60 days after the date of publication of this
If a request for a hearing/petition for leave to intervene is filed within the 60-day period, the Commission or a presiding officer designated by the Commission or by the Chief Administrative Judge of the Atomic Safety and Licensing Board Panel will rule on the request and/or petition; and the Secretary of the Commission (Secretary) or the Chief Administrative Judge of the Atomic Safety and Licensing Board Panel will issue a notice of a hearing or an appropriate order. In the event that no request for a hearing or petition for leave to intervene is filed within the 60-day period, the NRC may, upon completion of its evaluations and upon making the findings required under 10 CFR parts 51 and 54, renew the license without further notice.
As required by 10 CFR 2.309, a request for hearing or petition for leave to intervene must set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding, taking into consideration the limited scope of matters that may be considered pursuant to 10 CFR parts 51 and 54. Pursuant to
10 CFR 2.309(d), the request for hearing or petition for leave to intervene must provide the name, address, and telephone number of the requestor or petitioner; and specifically explain the reasons why intervention should be permitted with particular reference to the following factors for the Fermi 2 site: (1) The nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (2) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (3) the possible effect of any decision or order which may be entered in the proceeding on the requestor's/petitioner's interest. The request for hearing or petition for leave to intervene must also set forth the specific contentions which the requestor/petitioner seeks to have litigated at the proceeding.
In accordance with 10 CFR 2.309(f), each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the basis for each contention and a concise statement of the alleged facts or expert opinions which support the contention and on which the requestor/petitioner intends to rely at hearing. The requestor/petitioner must also provide references to those specific sources and documents on which the requestor/petitioner intends to rely to support its position on the issue. The requestor/petitioner must provide sufficient information to show that a genuine dispute exists with the applicant/licensee on a material issue of law or fact. This information must include references to specific portions of the application that the petitioner disputes and the supporting reasons for each dispute, or if the petitioner believes that the application fails to contain information on a relevant matter as required by law, the identification of each failure and the supporting reasons for the petitioner's belief. Contentions shall be limited to matters within the scope of the action under consideration. The contention must be one that, if proven, would entitle the requestor/petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Hearing requests, intervention petitions, and motions for leave to file new or amended contentions filed after the deadline will not be entertained absent a determination by the presiding officer that the filing demonstrates good cause by satisfying the three factors in 10 CFR 2.309(c)(1)(i)-(iii).
A State, local governmental body, or Federally-recognized Indian tribe may submit a request for hearing or a petition to intervene to the Commission to participate as a party to the proceeding under 10 CFR 2.309(h)(1). The request for hearing or petition to intervene must contain at least one admissible contention, and must designate a single representative for the hearing. The request for hearing or petition to intervene should be submitted to the Commission by August 18, 2014. The request or petition must be filed in accordance with the filing instructions in the “Electronic Submission (E-Filing)” section of this document, and should meet the requirements for requests for hearing and petitions for leave to intervene set forth in this section, except that under 10 CFR 2.309(h)(2) a State, local governmental body, or Federally-recognized Indian tribe, does not need to address the standing requirements in 10 CFR 2.309(d) if the proceeding pertains to a production or utilization facility and that facility is located within its boundaries. A State, local governmental body, or Federally-recognized Indian tribe, may also have the opportunity to participate under 10 CFR 2.315(c).
If a hearing is granted, any person who does not wish, or is not qualified, to become a party to the proceeding may, in the discretion of the presiding officer, be permitted to make a limited appearance pursuant to the provisions of 10 CFR 2.315(a). A person making a limited appearance may make an oral or written statement of position on the issues, but may not otherwise participate in the proceeding. A limited appearance may be made at any session of the hearing or at any prehearing conference, within the limits and on the conditions fixed by the presiding officer. Such statements of position shall not be considered evidence in the proceeding. Persons desiring to make a limited appearance are requested to inform the Secretary of the Commission by August 18, 2014.
The Commission requests that each contention be given a separate numeric or alpha designation within one of the following groups: (1) Technical (primarily related to safety concerns); (2) environmental; or (3) miscellaneous.
As specified in 10 CFR 2.309, if two or more requestors/petitioners seek to co-sponsor a contention or propose substantially the same contention, the requestors/petitioners will be required to jointly designate a representative who shall have the authority to act for the requestors/petitioners with respect to that contention.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition for leave to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC's E-Filing rule (72 FR 49139; August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper
To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on the NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. In order to serve documents through the Electronic Information Exchange System, users will be required to install a Web browser plug-in from the NRC's Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with the NRC's guidance available on the NRC's public Web site at
A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC's public Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by first-class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service upon depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket which is available to the public at
Detailed information about the license renewal process can be found under the Nuclear Reactors icon at
The NRC staff has verified that a copy of the license renewal application is also available to local residents near Fermi 2 at the Ellis Library and Reference Center, 3700 South Custer Road, Monroe, MI 48161.
For the Nuclear Regulatory Commission.
The ACRS Subcommittee on Plant Operations and Fire Protection will hold a meeting on July 24, 2014, at the U.S. NRC Region III Office, 2443 Warrenville Road, Lisle, IL 60532-4352.
The meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will meet with Region III staff to discuss items of mutual interest. The Subcommittee will hear presentations by and hold discussions with representatives of the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Mark Banks (Telephone 301-415-3718 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
The ACRS Subcommittee on Future Plant Designs will hold a meeting on July 8, 2014, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The entire meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will discuss additional results from several Design Acceptance Criteria (DAC) inspections completed for AP1000 Digital I&C and piping using the new inspection procedures. The Subcommittee will hear presentations by and hold discussions with the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Christina Antonescu (Telephone 301-415-6792 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
The ACRS Subcommittee on ESBWR will hold a meeting on July 7, 2014, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance with the exception of portions that may be closed to protect
The Subcommittee will review selected chapters of the NRC staff's Safety Evaluation Report regarding the Fermi, Unit 3, combined license application referencing the ESBWR design and the implementation of the lessons learned from the Fukushima accident. The Subcommittee will hear presentations by and hold discussions with representatives of the NRC staff, Detroit Edison, and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Christopher Brown (Telephone 301-415-7111 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (240-888-9835) to be escorted to the meeting room.
The ACRS Subcommittee on Planning and Procedures will hold a meeting on July 8, 2014, Room T-2B3, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance with the exception of a portion that may be closed pursuant to 5 U.S.C. 552b(c)(2) and (6) to discuss organizational and personnel matters that relate solely to the internal personnel rules and practices of the ACRS, and information the release of which would constitute a clearly unwarranted invasion of personal privacy.
The agenda for the subject meeting shall be as follows:
The Subcommittee will discuss proposed ACRS activities and related matters. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Quynh Nguyen (Telephone 301-415-5844 or Email:
Information regarding changes to the agenda, whether the meeting has been canceled or rescheduled, and the time allotted to present oral statements can be obtained by contacting the identified DFO. Moreover, in view of the possibility that the schedule for ACRS meetings may be adjusted by the Chairman as necessary to facilitate the conduct of the meeting, persons planning to attend should check with the DFO if such rescheduling would result in a major inconvenience.
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
Public meeting.
The U.S. Nuclear Regulatory Commission (NRC) plans to hold a public meeting to discuss NRC options regarding endorsement of ASME/ANS PRA standards and the staff proposed criteria for evaluating multi-module risk.
The public meeting will be held on June 26, 2014. See Section II, Public Meeting, of this document for more information on the meeting.
Please refer to Docket ID NRC-2014-0143 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
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Mary Drouin, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-251-7574; email:
The ASME/ANS Joint Committee on Nuclear Risk Management (JCNRM) plans to publish three Probabilistic Risk Assessment (PRA) standards for trial use at the end of this calendar year or the beginning of 2015: (1) Low Power Shutdown PRA Standard, (2) Level 2 PRA Standard and (3) Advanced Light Water Reactor (ALWR) PRA standard. At a public meeting, the NRC seeks to discuss with interested stakeholders options for the NRC to endorse use of these standards.
The NRC has been discussing multi-unit risk for many years with limited discussion on multi-module risk. The NRC staff plans to discuss their expectations for Multi-Module risk in a public meeting and in a white paper entitled “Multi-Module Risk-NRC Expectations” (ADAMS Accession No. ML14150A330). The paper will be issued and available to the public by June 20, 2014.
The public meeting will be held in Rockville, Maryland, at 21 Church Street in Room CSB 06B1 on June 26, 2014, at 8:00 a.m.
There will be two items on the agenda for the meeting. The first agenda item will be to discuss staff options for endorsement of the ASME/ANS standards to be issued for trial use and to solicit stakeholder input. The second agenda item will be discussion of the NRC white paper entitled “Multi—Module Risk-NRC Expectations” (ADAMS ML ML14150A330) which will be available to the public by June 20, 2014.
The purpose of these agenda items is for the NRC staff to answer questions, to provide clarification regarding the white paper, and to solicit early stakeholder comments on both of these subjects. This meeting will be a Category 2 public meeting.
For the Nuclear Regulatory Commission.
The Advisory Committee on Reactor Safeguards (ACRS) Subcommittee on Fukushima will hold a meeting on July 8, 2013, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The entire meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will review and discuss NRC's Severe Accident Research activities. The Subcommittee will hear presentations by and hold discussions with the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Weidong Wang (Telephone 301-415-6279 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
Draft interim staff guidance; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) is issuing draft Interim Staff Guidance (ISG) FSME-ISG-02, “Guidance for Conducting the Section 106 Process of the National Historic Preservation Act for Uranium Recovery Licensing Actions,” for review and comment. The purpose of this draft ISG is to assist NRC staff in conducting the Section 106 process of the National Historic Preservation Act of 1966, as amended (NHPA), specific to uranium recovery licensing actions. While this guidance is primarily intended for the NRC staff, it also provides useful information to participants in the Section 106 process for uranium recovery licensing actions.
Submit comments by September 2, 2014. Comments received after this date will be considered if it is practical to do so, but the NRC is able to assure consideration only for comments received on or before this date.
You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):
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For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Diana Diaz Toro, Office of Federal and State Materials and Environmental Management Programs, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; telephone: 301-415-0930; email:
Please refer to Docket ID NRC-2014-0142 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document by any of the following methods:
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Please include Docket ID NRC-2014-0142 in the subject line of your comment submission, in order to ensure that the NRC is able to make your comment submission available to the public in this docket.
The NRC cautions you not to include identifying or contact information that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment submissions into ADAMS.
The NRC is responsible for regulating the civilian use of nuclear materials and facilities in a manner that protects public health and safety from radiological hazards and common defense and security. The NRC has statutory authority to regulate and license uranium recovery facilities through the Atomic Energy Act of 1954, as amended (AEA) and the Uranium Mill Tailings Radiation Control Act of 1978. In part, these statutes require that the NRC to ensure the management of source material, as defined in AEA Section 11z., and byproduct material, as defined in AEA Section 11e.(2), conforms to applicable regulatory requirements.
License applicants initiate the proposed federal action by submitting an application to the NRC for projects or activities requiring an NRC license or approval. The NRC must then make a decision whether to grant or deny the applicant's request. In addition to the NRC staff's safety review, the NRC staff conducts an environmental review, as required under the National Environmental Policy Act of 1969, as amended (NEPA). Through the environmental review, the NRC evaluates the potential environmental impacts from the applicant's proposal. The NRC's NEPA implementing regulations are in Part 51 of Title 10 of the
Congress enacted the NHPA to support and encourage the preservation of prehistoric and historic resources. Section 106 of the NHPA requires federal agencies to take into account the effects of their undertakings on historic properties and allow the Advisory Council on Historic Preservation an opportunity to review and comment on the undertaking. The NHPA implementing regulations are in 36 CFR part 800, “Protection of Historic Properties.” Federal agencies carry out the Section 106 process through consultation as appropriate with the State Historic Preservation Officer, Tribal Historic Preservation Officer, other federal, state, and local governmental agencies, Tribal governments, other interested parties, and the public. The NRC conducts the Section 106 process as part of its reviews of requests for license applications. In accordance with 36 CFR 800.1(c), the NRC must complete the
The NRC's guidance for conducting environmental reviews in support of the Office of Federal and State Materials and Environmental Management Programs and Office of Nuclear Material Safety and Safeguards licensing and regulatory actions is provided in NUREG-1748, “Environmental Review Guidance for Licensing Actions Associated With Nuclear Material Safety and Safeguards Programs” (ADAMS Accession No. ML032450279). NUREG-1748 also includes general guidance for complying with the NHPA Section 106 process.
Over the past several years, an increase in the number of licensing action for
The NRC staff plans to revise the applicable sections of NUREG-1748 to include the guidance in this ISG. Until then, the NRC staff will use this ISG and revise and update the document as needed to clarify the content or incorporate subsequent modifications.
The NRC staff will review and consider the comments received in response to this request and revise the ISG as appropriate.
For the U.S. Nuclear Regulatory Commission.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 12(d)(1)(J) of the Investment Company Act of 1940 (the “1940 Act”) for exemptions from sections 12(d)(1)(A), (B), and (C) of the 1940 Act, under sections 6(c) and 17(b) of the 1940 Act for an exemption from section 17(a) of the 1940 Act, and under section 6(c) of the 1940 Act for an exemption from rule 12d1-2(a) under the 1940 Act.
Absolute Shares Trust (“Trust”), Millington Securities, Inc. (“Advisor”) and Foreside Fund Services, LLC (the “Distributor”).
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 July 7, 2014, 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.
Secretary, U.S. Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090. Applicants: Absolute Shares Trust, c/o Don Schreiber, Jr., 331 Newman Springs Road, Suite 122, Red Bank, NJ 07701; Millington Securities, Inc., c/o Don Schreiber, Jr., 331 Newman Springs Road, Suite 122, Red Bank, NJ 07701; Foreside Fund Services LLC, Three Canal Plaza, Suite 100, Portland, ME 04101.
Anil K. Abraham, Senior Special Counsel, at (202) 551-2614, or Daniele Marchesani, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's 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. Absolute Shares Trust is an open-end management company registered under the 1940 Act and organized as a Delaware statutory trust. The Trust has multiple series (“Funds”), which pursue distinct investment objectives and strategies.
2. Millington Securities, Inc., a Delaware limited liability company, is a registered investment adviser under the Investment Advisers Act of 1940 (the “Advisers Act”). Millington Securities, Inc., or an entity controlling, controlled by, or under common control with Millington Securities, Inc., serves, or will serve, as the investment adviser to each of the Funds.
3. Applicants request relief to the extent necessary to permit: (a) Each Fund (each, a “Fund of Funds,” and collectively, the “Funds of Funds”) to acquire shares of registered open-end management investment companies (each an “Unaffiliated Open-End Investment Company”), registered closed-end management investment companies, business development companies (each registered closed-end management investment company and each business development company, an “Unaffiliated Closed-End Investment Company” and, together with the Unaffiliated Open-End Investment Companies, the “Unaffiliated Investment Companies”), and registered unit investment trusts (“UITs”) (the “Unaffiliated Trusts,” collectively with the Unaffiliated Investment Companies, the “Unaffiliated Funds”), in each case, that are not part of the same “group of investment companies” as the Funds of Funds;
4. Applicants also request an exemption under section 6(c) from rule 12d1-2 under the 1940 Act to permit any existing or future Fund of Funds that relies on section 12(d)(1)(G) of the 1940 Act (“Section 12(d)(1)(G) Fund of Funds”) and that otherwise complies with rule 12d1-2 under the 1940 Act, to also invest, to the extent consistent with its investment objective(s), policies, strategies and limitations, in other financial instruments that may not be securities within the meaning of section 2(a)(36) of the 1940 Act (“Other Investments”).
1. Section 12(d)(1)(A) of the 1940 Act, in relevant part, prohibits a registered investment company from acquiring shares of an investment company if the securities represent more than 3% of the total outstanding voting stock of the acquired company, more than 5% of the total assets of the acquiring company, or, together with the securities of any other investment companies, more than 10% of the total assets of the acquiring company. Section 12(d)(1)(B) of the 1940 Act prohibits a registered open-end investment company, its principal underwriter, and any Broker from selling the investment company's shares to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company's voting stock, or if the sale will cause more than 10% of the acquired company's voting stock to be owned by investment companies generally. Section 12(d)(1)(C) prohibits an investment company from acquiring any security issued by a registered closed-end investment company if such acquisition would result in the acquiring company, any other investment companies having the same investment adviser, and companies controlled by such investment companies, collectively, owning more than 10% of the outstanding voting stock of the registered closed-end investment company.
2. Section 12(d)(1)(J) of the 1940 Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities or transactions, from any provision of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors. Applicants request an exemption under section 12(d)(1)(J) of the 1940 Act from the limitations of sections 12(d)(1)(A), (B) and (C) to the extent necessary to permit: (i) The Funds of Funds to acquire shares of Underlying Funds in excess of the limits set forth in section 12(d)(1)(A) and (C) of the 1940 Act; and (ii) the Underlying Funds, their principal underwriters and any Broker to sell shares of the Underlying Funds to the Funds of Funds in excess of the limits set forth in section 12(d)(1)(B) of the 1940 Act.
3. Applicants state that the proposed arrangement will not give rise to the policy concerns underlying sections 12(d)(1)(A), (B), and (C), which include concerns about undue influence by a fund of funds over underlying funds, excessive layering of fees, and overly complex fund structures. Accordingly, applicants believe that the requested exemption is consistent with the public interest and the protection of investors.
4. Applicants submit that the proposed structure will not result in the exercise of undue influence by a Fund of Funds or its affiliated persons over the Underlying Funds. Applicants assert that the concern about undue influence does not arise in connection with a Fund of Funds' investment in the Affiliated Funds because they are part of the same group of investment companies. To limit the control a Fund of Funds or Fund of Funds Affiliate
5. With respect to closed-end Underlying Funds, applicants note that although closed-end funds may not be unduly influenced by a holder's right of redemption, closed-end Underlying Funds may be unduly influenced by a holder's ability to vote a large block of stock. To address this concern, applicants submit that, with respect to a Fund's investment in an Unaffiliated Closed-End Investment Company, (i) each member of the Group or Sub-Adviser Group that is an investment company or an issuer that would be an investment company but for section 3(c)(1) or 3(c)(7) of the 1940 Act will vote its shares of the Unaffiliated Closed-End Investment Company in the manner prescribed by section 12(d)(1)(E) of the 1940 Act and (ii) each other member of the Group or Sub-Adviser Group will vote its shares of the Unaffiliated Closed-End Investment Company in the same proportion as the vote of all other holders of the same type of such Unaffiliated Closed-End Investment Company's shares. Applicants state that, in this way, an Unaffiliated Closed-End Investment Company will be protected from undue influence by a Fund of Funds through the voting of the Unaffiliated Closed-End Investment Company's shares.
6. Applicants propose other conditions to limit the potential for undue influence over the Unaffiliated Funds, including that no Fund of Funds or Fund of Funds Affiliate (except to the extent it is acting in its capacity as an investment adviser to an Unaffiliated Investment Company or sponsor to an Unaffiliated Trust) will cause an Unaffiliated Fund to purchase a security in an offering of securities during the existence of any underwriting or selling syndicate of which a principal underwriter is an Underwriting Affiliate (“Affiliated Underwriting”).
7. To further ensure that an Unaffiliated Investment Company understands the implications of a Fund of Funds' investment under the requested exemptive relief, prior to its investment in the shares of an Unaffiliated Investment Company in excess of the limit of section 12(d)(1)(A)(i) of the 1940 Act, a Fund of Funds and the Unaffiliated Investment Company will execute an agreement stating, without limitation, that each of their boards of directors or trustees (for any entity, the “Board”) and their investment advisers understand the terms and conditions of the order and agree to fulfill their responsibilities under the order (the “Participation Agreement”). Applicants note that an Unaffiliated Investment Company (including an ETF or an Unaffiliated Closed-End Investment Company) would also retain its right to reject any initial investment by a Fund of Funds in excess of the limits in section 12(d)(1)(A)(i) of the 1940 Act by declining to execute the Participation Agreement with the Fund of Funds. In addition, an Unaffiliated Investment Company (other than an ETF or closed-end fund whose shares are purchased by a Fund of Funds in the secondary market) will retain its right at all times to reject any investment by a Fund of Funds. Finally, subject solely to the giving of notice to a Fund of Funds and the passage of a reasonable notice period, an Unaffiliated Fund (including an ETF or an Unaffiliated Closed-End Investment Company) could terminate a Participation Agreement with the Fund of Funds.
8. Applicants state that they do not believe that the proposed arrangement will result in excessive layering of fees. The Board of each Fund of Funds, including a majority of the trustees who are not “interested persons” within the meaning of section 2(a)(19) of the 1940 Act (the “Independent Trustees”), will find that the management or advisory fees charged under a Fund of Funds' advisory contract are based on services provided that are in addition to, rather than duplicative of, services provided under the advisory contract(s) of any Underlying Fund in which the Fund of Funds may invest. In addition, the Advisor will waive fees otherwise payable to it by a Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by an Unaffiliated Investment Company under rule 12b-1 under the 1940 Act) received from an Unaffiliated Fund by the Advisor, or an affiliated person of the Advisor, other than any advisory fees paid to the Advisor or an affiliated person of the Advisor by the Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund.
9. Applicants further state that any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to funds of funds set forth in in rule 2830 of the Conduct Rules of the NASD (“NASD Conduct Rule 2830”).
10. Applicants submit that the proposed arrangement will not create an overly complex fund structure. Applicants note that no Underlying Fund will acquire securities of any other investment company or company relying on section 3(c)(1) or 3(c)(7) of the 1940 Act in excess of the limits contained in section 12(d)(1)(A) of the 1940 Act, except in certain circumstances identified in condition 12 below.
1. Section 17(a) of the 1940 Act generally prohibits sales or purchases of securities between a registered investment company and any affiliated person of the company. Section 2(a)(3) of the 1940 Act defines an “affiliated person” of another person to include (a) any person directly or indirectly owning, controlling, or holding with power to vote, 5% or more of the outstanding voting securities of the other person; (b) any person 5% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote by the other person; and (c) any person directly or indirectly controlling, controlled by, or under common control with the other person.
2. Applicants state that the Funds of Funds and the Affiliated Funds may be deemed to be under the common control of the Advisor and, therefore, affiliated
3. Section 17(b) of the 1940 Act authorizes the Commission to grant an order permitting a transaction otherwise prohibited by section 17(a) if it finds that (i) the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned; (ii) the proposed transaction is consistent with the policies of each registered investment company concerned; and (iii) the proposed transaction is consistent with the general purposes of the 1940 Act. Section 6(c) of the 1940 Act permits the Commission to exempt any person or transactions from any provision of the 1940 Act 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 1940 Act.
4. Applicants submit that the proposed transactions satisfy the standards for relief under sections 17(b) and 6(c) of the 1940 Act. Applicants state that the terms of the transactions are reasonable and fair and do not involve overreaching. Applicants state that the terms upon which an Underlying Open-End Fund will sell its shares to or purchase its shares from a Fund of Funds will be in accordance with the rules and regulations under the 1940 Act.
1. Section 12(d)(1)(G) of the 1940 Act provides that section 12(d)(1) will not apply to securities of an acquired company purchased by an acquiring company if: (i) The acquiring company and acquired company are part of the same “group of investment companies,” as defined in section 12(d)(1)(G)(ii) of the 1940 Act; (ii) the acquiring company holds only securities of acquired companies that are part of the same “group of investment companies,” as defined in section 12(d)(1)(G)(ii) of the 1940 Act, government securities, and short-term paper; (iii) the aggregate sales loads and distribution-related fees of the acquiring company and the acquired company are not excessive under rules adopted pursuant to section 22(b) or section 22(c) of the 1940 Act by a securities association registered under section 15A of the 1934 Act or by the Commission; and (iv) the acquired company has a policy that prohibits it from acquiring securities of registered open-end management investment companies or registered UITs in reliance on section 12(d)(1)(F) or (G) of the 1940 Act.
2. Rule 12d1-2 under the 1940 Act permits a registered open-end investment company or a registered UIT that relies on section 12(d)(1)(G) of the 1940 Act to acquire, in addition to securities issued by another registered investment company in the same group of investment companies, government securities, and short-term paper: (1) Securities issued by an investment company that is not in the same group of investment companies, when the acquisition is in reliance on section 12(d)(1)(A) or 12(d)(1)(F) of the 1940 Act; (2) securities (other than securities issued by an investment company); and (3) securities issued by a money market fund, when the investment is in reliance on rule 12d1-1 under the 1940 Act. For the purposes of rule 12d1-2, “securities” means any security as defined in section 2(a)(36) of the 1940 Act.
3. Applicants state that the proposed arrangement would comply with rule 12d1-2 under the 1940 Act, but for the fact that the Section 12(d)(1)(G) Funds of Funds may invest a portion of their assets in Other Investments. Applicants request an order under section 6(c) of the 1940 Act for an exemption from rule 12d1-2(a) to allow the Section 12(d)(1)(G) Funds of Funds to invest in Other Investments. Applicants assert that permitting a Section 12(d)(1)(G) Fund of Funds to invest in Other Investments as described in the application would not raise any of the concerns that section 12(d)(1) of the 1940 Act was intended to address.
4. Consistent with its fiduciary obligations under the 1940 Act, a Section 12(d)(1)(G) Fund of Funds' Board will review the advisory fees charged by the Section 12(d)(1)(G) Fund of Funds' investment adviser(s) to ensure that the fees are based on services provided that are in addition to, rather than duplicative of, services provided pursuant to the advisory agreement of any investment company in which the Section 12(d)(1)(G) Fund of Funds may invest.
Applicants agree that the order granting the requested relief to permit Funds of Funds to invest in Underlying Funds shall be subject to the following conditions:
1. The members of the Group will not control (individually or in the aggregate) an Unaffiliated Fund within the meaning of section 2(a)(9) of the 1940 Act. The members of a Sub-Adviser Group will not control (individually or in the aggregate) an Unaffiliated Fund within the meaning of section 2(a)(9) of the 1940 Act. With respect to a Fund's investment in an Unaffiliated Closed-End Investment Company, (i) each member of the Group or Sub-Adviser Group that is an investment company or an issuer that would be an investment company but for section 3(c)(1) or 3(c)(7) of the 1940 Act will vote its shares of the Unaffiliated Closed-End Investment Company in the manner prescribed by section 12(d)(1)(E) of the 1940 Act and (ii) each other member of the Group or Sub-Adviser Group will vote its shares of the Unaffiliated Closed-End Investment Company in the same proportion as the vote of all other holders of the same type of such Unaffiliated Closed-End Investment Company's shares. If, as a result of a
2. No Fund of Funds or Fund of Funds Affiliate will cause any existing or potential investment by the Fund of Funds in an Unaffiliated Fund to influence the terms of any services or transactions between the Fund of Funds or a Fund of Funds Affiliate and the Unaffiliated Fund or an Unaffiliated Fund Affiliate.
3. The Board of each Fund of Funds, including a majority of the Independent Trustees, will adopt procedures reasonably designed to ensure that its Advisor and any Sub-Adviser to the Fund of Funds are conducting the investment program of the Fund of Funds without taking into account any consideration received by the Fund of Funds or Fund of Funds Affiliate from an Unaffiliated Fund or an Unaffiliated Fund Affiliate in connection with any services or transactions.
4. Once an investment by a Fund of Funds in the securities of an Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the 1940 Act, the Board of the Unaffiliated Investment Company, including a majority of the Independent Trustees, will determine that any consideration paid by the Unaffiliated Investment Company to a Fund of Funds or a Fund of Funds Affiliate in connection with any services or transactions: (a) Is fair and reasonable in relation to the nature and quality of the services and benefits received by the Unaffiliated Investment Company; (b) is within the range of consideration that the Unaffiliated Investment Company would be required to pay to another unaffiliated entity in connection with the same services or transactions; and (c) does not involve overreaching on the part of any person concerned. This condition does not apply with respect to any services or transactions between an Unaffiliated Investment Company and its investment adviser(s), or any person controlling, controlled by, or under common control with such investment adviser(s).
5. No Fund of Funds or Fund of Funds Affiliate (except to the extent it is acting in its capacity as an investment adviser to an Unaffiliated Investment Company or sponsor to an Unaffiliated Trust) will cause an Unaffiliated Fund to purchase a security in any Affiliated Underwriting.
6. The Board of an Unaffiliated Investment Company, including a majority of the Independent Trustees, will adopt procedures reasonably designed to monitor any purchases of securities by the Unaffiliated Investment Company in an Affiliated Underwriting once an investment by a Fund of Funds in the securities of the Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the 1940 Act, including any purchases made directly from an Underwriting Affiliate. The Board of the Unaffiliated Investment Company will review these purchases periodically, but no less frequently than annually, to determine whether the purchases were influenced by the investment by the Fund of Funds in the Unaffiliated Investment Company. The Board of the Unaffiliated Investment Company will consider, among other things: (a) Whether the purchases were consistent with the investment objectives and policies of the Unaffiliated Investment Company; (b) how the performance of securities purchased in an Affiliated Underwriting compares to the performance of comparable securities purchased during a comparable period of time in underwritings other than Affiliated Underwritings or to a benchmark such as a comparable market index; and (c) whether the amount of securities purchased by the Unaffiliated Investment Company in Affiliated Underwritings and the amount purchased directly from an Underwriting Affiliate have changed significantly from prior years. The Board of the Unaffiliated Investment Company will take any appropriate actions based on its review, including, if appropriate, the institution of procedures designed to ensure that purchases of securities in Affiliated Underwritings are in the best interest of shareholders.
7. Each Unaffiliated Investment Company will maintain and preserve permanently, in an easily accessible place, a written copy of the procedures described in the preceding condition, and any modifications to such procedures, and will maintain and preserve for a period of not less than six years from the end of the fiscal year in which any purchase in an Affiliated Underwriting occurred, the first two years in an easily accessible place, a written record of each purchase of securities in an Affiliated Underwriting once an investment by a Fund of Funds in the securities of an Unaffiliated Investment Company exceeds the limit of section 12(d)(1)(A)(i) of the 1940 Act, setting forth (1) the party from whom the securities were acquired, (2) the identity of the underwriting syndicate's members, (3) the terms of the purchase, and (4) the information or materials upon which the determinations of the Board of the Unaffiliated Investment Company were made.
8. Prior to its investment in shares of an Unaffiliated Investment Company in excess of the limit set forth in section 12(d)(1)(A)(i) of the 1940 Act, the Fund of Funds and the Unaffiliated Investment Company will execute a Participation Agreement stating, without limitation, that their Boards and their investment advisers understand the terms and conditions of the order and agree to fulfill their responsibilities under the order. At the time of its investment in shares of an Unaffiliated Investment Company in excess of the limit set forth in section 12(d)(1)(A)(i), a Fund of Funds will notify the Unaffiliated Investment Company of the investment. At such time, the Fund of Funds will also transmit to the Unaffiliated Investment Company a list of the names of each Fund of Funds Affiliate and Underwriting Affiliate. The Fund of Funds will notify the Unaffiliated Investment Company of any changes to the list as soon as reasonably practicable after a change occurs. The Unaffiliated Investment Company and the Fund of Funds will maintain and preserve a copy of the order, the Participation Agreement, and the list with any updated information for the duration of the investment and for a period of not less than six years thereafter, the first two years in an easily accessible place.
9. Before approving any advisory contract under section 15 of the 1940 Act, the Board of each Fund of Funds, including a majority of the Independent Trustees, shall find that the advisory fees charged under the advisory contract are based on services provided that are in addition to, rather than duplicative of, services provided under the advisory contract(s) of any Underlying Fund in which the Fund of Funds may invest. Such finding, and the basis upon which the finding was made, will be recorded fully in the minute books of the appropriate Fund of Funds.
10. The Advisor will waive fees otherwise payable to it by a Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by an Unaffiliated Investment Company pursuant to rule 12b-1 under the 1940 Act) received from an Unaffiliated Fund by the Advisor, or an affiliated person of the Advisor, other than any advisory fees paid to the Advisor or its affiliated person by the Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund. Any Sub-Adviser will waive fees otherwise payable to the Sub-Adviser, directly or indirectly, by the Fund of Funds in an amount at least equal to any compensation received by the Sub-Adviser, or an affiliated person of the Sub-Adviser, from an Unaffiliated Fund, other than any advisory fees paid to the Sub-Adviser or its affiliated person by the Unaffiliated Investment Company, in connection with the investment by the Fund of Funds in the Unaffiliated Fund made at the direction of the Sub-Adviser. In the event that the Sub-Adviser waives fees, the benefit of the waiver will be passed through to the Fund of Funds.
11. Any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to funds of funds set forth in NASD Conduct Rule 2830.
12. No Underlying Fund will acquire securities of any other investment company or company relying on section 3(c)(1) or 3(c)(7) of the 1940 Act, in excess of the limits contained in section 12(d)(1)(A) of the 1940 Act, except to the extent that such Underlying Fund: (a) Acquires such securities in compliance with section 12(d)(1)(E) of the 1940 Act and is either an Affiliated Fund or is in the same “group of investment companies” as its corresponding master fund; (b) receives securities of another investment company as a dividend or as a result of a plan of reorganization of a company (other than a plan devised for the purpose of evading section 12(d)(1) of the 1940 Act); or (c) acquires (or is deemed to have acquired) securities of another investment company pursuant to exemptive relief from the Commission permitting such Underlying Fund to: (i) Acquire securities of one or more investment companies for short-term cash management purposes or (ii) engage in inter-fund borrowing and lending transactions.
In addition, Applicants agree that the order granting the requested relief to permit Section 12(d)(1)(G) Funds of Funds to invest in Other Investments shall be subject to the following condition:
1. Applicants will comply with all provisions of rule 12d1-2 under the 1940 Act, except for paragraph (a)(2) to the extent that it restricts any Section 12(d)(1)(G) Fund of Funds from investing in Other Investments as described in the application.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of application for an order under section 57(i) of the Investment Company Act of 1940 (the “Act”) and rule 17d-1 under the Act to permit certain joint transactions otherwise prohibited by section 57(a)(4) of the Act and rule 17d-1 under the Act.
Secretary, U.S. Securities and Exchange Commission, 100 F St. NE., Washington, DC 20549-1090. Applicants: c/o Richard Siegel, Esq., H.I.G. WhiteHorse Advisers, LLC, 1450 Brickell Avenue, 31st Floor, Miami, FL 33131.
Emerson S. Davis, Senior Counsel, at (202) 551-6868, or Daniele Marchesani, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's 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 Company is an externally managed, non-diversified, closed-end management investment company that has elected to be regulated as a BDC under the Act.
2. The Company Adviser, a Delaware limited liability company, is registered under the Investment Advisers Act of 1940 (“Advisers Act”) and is the Company's investment adviser. H.I.G Capital, L.L.C. is an alternative investment and asset management firm and is registered under the Advisers Act. WhiteHorse Capital, LLC serves as the investment adviser for WhiteHorse VI, Ltd., WhiteHorse VII, Ltd. and WhiteHorse VIII. Ltd in its capacity as the collateral manager to each of those three entities.
3. The Existing Private Funds are entities formed under the laws of Delaware or under the laws of the Cayman Islands. In reliance on the exclusion from the definition of “Investment Company” provided by section 3(c)(7) of the Act, none of the Existing Private Funds will be registered under the Act. Each Existing Private Fund is managed by the Current Advisers to Private Funds in accordance with an investment advisory agreement (collectively, the “Advisory Agreements”). The Company expects that any portfolio company that is an appropriate investment for a Private Fund
4. Applicants seek an order (“Order”)
5. The Company may, from time to time, form a special purpose subsidiary (a “Wholly-Owned Investment Subsidiary”).
6. Applicants represent that the Current Advisers to Private Funds will refer to the Company Adviser all Potential Co-Investment Transactions within the Company's Objectives and Strategies
7. Other than pro rata dispositions and Follow-On Investments
8. With respect to the pro rata dispositions and Follow-On Investments provided in conditions 7 and 8, the Company may participate in a pro rata disposition or Follow-On Investment without obtaining prior approval of the Required Majority if, among other things: (i) The proposed participation of the Company and each Private Fund in such disposition or Follow-On-Investment is proportionate to its outstanding investments in the issuer immediately preceding the disposition or Follow-On Investment, as the case may be; and (ii) the Board has approved the Company's participation in pro rata dispositions or Follow-On Investments as being in the best interests of the Company. If the Board does not so approve, any such disposition or Follow-On Investment will be submitted to the Company's Eligible Directors. The Board of the Company may at any time rescind, suspend or qualify its approval of pro rata dispositions and Follow-On Investments with the result that all dispositions and/or Follow-On Investments must be submitted to the Eligible Directors.
9. No Independent Director will have any direct or indirect financial interest in any Co-Investment Transaction or any interest in any portfolio company, other than through an interest (if any) in the securities of the Company.
1. Section 57(a)(4) of the Act prohibits certain affiliated persons of a BDC from participating in a joint transaction with the BDC in contravention of rules as prescribed by the Commission. Section 57(i) of the Act provides that, until the Commission prescribes rules under section 57(a)(4), the Commission's rules under section 17(d) of the Act applicable to registered closed-end investment companies will be deemed to apply to BDCs. Because the Commission has not adopted any rules under section 57(a)(4), rule 17d-1 applies to BDCs. The Company Adviser and any Private Fund that it advises could be deemed to be persons related to the Company in a manner described by section 57(b) and therefore prohibited by section 57(a)(4) and rule 17d-1 from participating in the Co-Investment Program. In addition, because the other Advisers are “affiliated persons” of the Company Adviser, such Advisers and Private Funds advised by any of them could be deemed to be persons related to the Company in a manner described by section 57(b) and also prohibited from participating in the Co-Investment Program. Finally, because WhiteHorse Warehouse and any other Wholly-Owned Investment Subsidiary are controlled by the Company, they are subject to section 57(a)(4), and thus also subject to the provisions of rule 17d-1.
2. Rule 17d-1, as made applicable to BDCs by section 57(i), prohibits any person who is related to a BDC in a manner described in section 57(b), acting as principal, from participating in, or effecting any transaction in connection with, any joint enterprise or other joint arrangement or profit-sharing plan in which the BDC is a participant, absent an order from the Commission. In passing upon applications under rule 17d-1, the Commission considers whether the company's participation in the joint transaction is consistent with the provisions, policies, and purposes of the Act and the extent to which such participation is on a basis different from or less advantageous than that of other participants.
3. Applicants state that they expect that co-investment in portfolio companies by the Company and the Private Funds will increase favorable investment opportunities for the Company and the Private funds.
4. Applicants submit that the Required Majority will approve each Co-Investment Transaction before investment, and other protective conditions set forth in the application, will ensure that the Company will be treated fairly. Applicants state that the Company's participation in the Co-Investment Transactions will be consistent with the provisions, policies, and purposes of the Act and on a basis that is not different from or less advantageous than that of other participants.
Applicants agree that any order granting the requested relief will be subject to the following conditions:
1. Each time an investment adviser considers a Potential Co-Investment Transaction for a Private Fund that falls within the Company's then-current Objectives and Strategies, the Company Adviser will make an independent determination of the appropriateness of such investment for the Company in light of the Company's then-current circumstances.
2. (a) If the Company Adviser deems the Company's participation in any Potential Co-Investment Transaction to be appropriate for the Company, it will then determine an appropriate level of investment for the Company;
(b) If the aggregate amount recommended by the Company Adviser to be invested in such Potential Co-Investment Transaction by the Company, together with the amount proposed to be invested by the Private Funds, collectively, in the same transaction, exceeds the amount of the investment opportunity, then the investment opportunity will be allocated among them pro rata based on each such party's capital available for investment in the asset class being allocated, up to the amount proposed to be invested by each party. The Company Adviser will provide the Eligible Directors with information concerning the Private Funds' available capital to assist the Eligible Directors with their review of the Company's investments for compliance with these allocation procedures; and
(c) After making the determinations required in conditions 1 and 2(a), the Company Adviser will then distribute written information concerning the Potential Co-Investment Transaction, including the amount proposed to be invested by the Company and any Private Fund, to the Eligible Directors for their consideration. The Company will co-invest with the Private Funds only if, prior to participating in such Co-Investment Transaction, the Required Majority concludes that:
(i) The terms of the transaction, including the consideration to be paid, are reasonable and fair to the Company and its stockholders and do not involve overreaching in respect of the Company or its stockholders on the part of any person concerned;
(ii) the transaction is consistent with:
(A) the interests of the stockholders of the Company; and
(B) the Company's then-current Objectives and Strategies;
(iii) the investment by the Private Funds would not disadvantage the Company, and participation by the Company would not be on a basis different from, or less advantageous than, that of the Private Funds; provided, that if any of the Private Funds, but not the Company itself, gains the right to nominate a director for election to a portfolio company's board of directors or the right to have a board observer or any similar right to participate in the governance or management of the portfolio company,
(A) The Eligible Directors will have the right to ratify the selection of such director or board observer, if any;
(B) the Advisers agree to, and do, provide periodic reports to the Company's Board with respect to the actions of the director or the information received by the board observer or obtained through the exercise of any similar right to participate in the governance or management of the portfolio company; and
(C) any fees or other compensation that any Private Fund or any affiliated person of any Private Fund receives in connection with the right of the Private Funds to nominate a director or appoint a board observer or otherwise to participate in the governance or management of the portfolio company will be shared proportionately among the participating Private Funds (which may, in turn, share their portion with their affiliated persons) and the Company in accordance with the amount of each party's investment; and
(iv) the proposed investment by the Company will not benefit the Advisers or the Private Funds, or any affiliated person of any of them (other than the parties to the Co-Investment Transaction), except (a) to the extent permitted by condition 13; (b) to the extent permitted by sections 17(e) or 57(k) of the Act as applicable; (c) indirectly, as a result of an interest in the securities issued by one of the parties to the Co-Investment Transaction; or (d) in the case of fees or other compensation described in condition 2(c)(iii)(C).
3. The Company has the right to decline to participate in any Potential Co-Investment Transaction or to invest less than the amount proposed.
4. The Company Adviser will present to the Board, on a quarterly basis, a record of all investments in Potential Co-Investment Transactions made by the Private Funds during the preceding quarter that fell within the Company's then-current Objectives and Strategies that were not made available to the Company and an explanation of why the investment opportunities were not offered to the Company. All information presented to the Board pursuant to this condition will be kept for the life of the Company and at least two years thereafter, and will be subject to examination by the Commission and its Staff.
5. Except for Follow-On Investments made in accordance with condition 8, the Company will not invest in reliance on the Order in any issuer in which any Private Fund or any affiliated person of the Private Funds is an existing investor.
6. The Company will not participate in any Potential Co-Investment Transaction unless the terms, conditions, price, class of securities to be purchased, settlement date and registration rights will be the same for the Company as for each participating Private Fund. The grant to a Private Fund, but not the Company, of the right to nominate a director for election to a portfolio company's board of directors, the right to have an observer on the board of directors or similar rights to participate in the governance or management of the portfolio company will not be interpreted so as to violate this condition 6, if conditions 2(c)(iii)(A), (B) and (C) are met.
7. (a) If any Private Fund elects to sell, exchange or otherwise dispose of an interest in a security that was acquired in a Co-Investment Transaction, the Company Adviser will:
(i) Notify the Company of the proposed disposition at the earliest practical time; and
(ii) formulate a recommendation as to participation by the Company in any such disposition.
(b) The Company will have the right to participate in such disposition on a proportionate basis at the same price and on the same terms and conditions as those applicable to the participating Private Funds.
(c) The Company may participate in such disposition without obtaining prior approval of the Required Majority if: (i) The proposed participation of the Company and of each Private Fund in such disposition is proportionate to its outstanding investment in the issuer immediately preceding the disposition; (ii) the Board has approved as being in the best interests of the Company the ability to participate in such dispositions on a pro rata basis (as described in greater detail in this application); and (iii) the Board is provided on a quarterly basis with a list of all dispositions made in accordance with this condition. In all other cases, the Company Adviser will provide its written recommendation as to the Company's participation to the Eligible Directors, and the Company will participate in such disposition solely to the extent that a Required Majority determines that it is in the Company's best interests.
(d) The Company and each participating Private Fund shall each bear its own expenses in connection with any such disposition.
8. (a) If any Private Fund desires to make a Follow-On Investment in a portfolio company whose securities were acquired in a Co-Investment Transaction, the Company Adviser will:
(i) Notify the Company of the proposed transaction at the earliest practical time; and
(ii) formulate a recommendation as to the proposed participation, including the amount of the proposed Follow-On investment, by the Company.
(b) The Company may participate in such Follow-On Investment without obtaining prior approval of the Required Majority if: (i) The proposed participation of the Company and each Private Fund in such investment is proportionate to its outstanding investment in the issuer immediately preceding the Follow-On Investment; and (ii) the Board has approved as being in the best interests of the Company the ability to participate in Follow-On Investments on a pro rata basis (as described in greater detail in this application). In all other cases, the Company Adviser will provide its written recommendation as to the Company's participation to the Eligible Directors, and the Company will participate in such Follow-On Investment solely to the extent that a Required Majority determines that it is in the Company's best interests.
(c) If with respect to any Follow-On Investment:
(i) The amount of the opportunity is not based on the Company's and the Private Funds' outstanding investments immediately preceding the Follow-On Investment; and
(ii) the aggregate amount recommended by the Company Adviser to be invested by the Company in the Follow-On Investment, together with the amount proposed to be invested by the participating Private Funds in the same transaction, exceeds the amount of the opportunity, then the amount invested by each such party will be allocated among them pro rata based on the ratio of capital available for investment in the asset class being allocated of each party, up to the amount proposed to be invested by each.
(d) The acquisition of Follow-On Investments as permitted by this condition will be considered a Co-Investment Transaction for all purposes and be subject to the other conditions set forth in this application.
9. The Independent Directors will be provided quarterly for review all information concerning Potential Co-Investment Transactions and Co-Investment Transactions, including investments made by the Private Funds
10. The Company will maintain the records required by section 57(f)(3) of the Act as if each of the investments permitted under these conditions were approved by the Required Majority under section 57(f) of the Act.
11. No Independent Directors will also be a director, general partner, managing member or principal, or otherwise an “affiliated person” (as defined in the Act) of any Private Fund.
12. The expenses, if any, associated with acquiring, holding or disposing of any securities acquired in a Co-Investment Transaction (including, without limitation, the expenses of the distribution of any such securities registered for sale under the 1933 Act) will, to the extent not payable by an Adviser under any agreement with the Company or the Private Funds, be shared by the Company and the Private Funds in proportion to the relative amounts of the securities held or being acquired or disposed of, as the case may be.
13. Any transaction fee (including break-up or commitment fees but excluding broker's fees contemplated by section 17(e) or 57(k) of the Act or received in connection with a Co-Investment Transaction will be distributed to the Company and the Private Funds on a pro rata basis, based on the amounts they invested or committed, as the case may be, in such Co-Investment Transaction. If any transaction fee is to be held by an Adviser to a Private Fund pending consummation of the Co-Investment Transaction, the fee will be deposited into an account maintained by such Adviser at a bank or banks having the qualifications prescribed in section 26(a)(I) of the Act, and such account will earn a competitive rate of interest that will also be divided pro rata among the Company and the participating Private Funds based on the amounts they invest in such Co-Investment Transaction. None of the Private Funds, Advisers of the Private Funds nor any affiliated person of the Company will receive additional compensation or remuneration of any kind as a result of, or in connection with, a Co-Investment Transaction (other than (i) in the case of the Company and the participating Private Funds, the pro rata transaction fees described above and fees or other compensation described in condition 2(c)(iii)(C) and (ii) in the case of the Advisers, investment advisory fees paid in accordance with the Advisory Agreements).
For the Commission, by the Division of Investment Management, under delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes to amend its fees and rebates applicable to Members
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 its Fee Schedule to: (i) Delete Flag RC, which routes to the NSX and adds liquidity; and (ii) make a corrective change to the definition of ADV to state that ADV includes shared routed by the Exchange.
The Exchange proposes to amend its Fee Schedule to delete Flag RC, which routes to the NSX and adds liquidity, in response to the NSX's announcement that it will cease market operations and its last day of trading will be Friday, May 30, 2014.
The Exchange proposes to make a corrective change to the definition of ADV to state that a Member's ADV
The Exchange's Fee Schedule currently states that Flag 7, which is yielded on orders routed during the pre and post market sessions, is considered when determining the liquidity adding rebate that the Exchange will provide to Members based on its tiered pricing structure. In harmonizing its definition of ADV with BATS and BYX, the Exchange mistakenly included a provision that excluded routed shares from the definition of ADV, thereby creating a conflict with the above provision in the Fee Schedule stating that Flag 7 is considered when determining the liquidity adding rebate under its tiered pricing structure. The Exchange now seeks to make a corrective change to the definition of ADV to state that routed orders are included in a Member's ADV calculation. The proposed rule change is designed to resolve a conflict in the Fee Schedule between the definition of ADV and the inclusion of orders that yield Flag 7 when determining the liquidity adding rebate under its tiered pricing structure. The Exchange notes that its proposal conforms to an existing practice and does not modify the fees or rebate that the Exchange has been providing its Members for achieving tier-based pricing.
The Exchange proposes to implement these amendments to its Fee Schedule on June 2, 2014.
The Exchange believes that the proposed rule change is consistent with the objectives of Section 6 of the Act,
The Exchange believes that its proposal to delete Flag RC in its Fee Schedule represents an equitable allocation of reasonable dues, fees, and other charges among Members and other persons using its facilities. The proposed change is in response to NSX's announcement that it will cease market operations and its last day of trading will Friday, May 30, 2014.
The Exchange believes that correcting an inadvertent error in the definition of ADV with regard to routed orders is reasonable because it will increase the level of transparency on the Exchange's Fee Schedule and improve the Exchange's ability to effectively convey the criteria necessary to achieve tier-based pricing and resolve a conflict in the Fee Schedule between the definition of ADV and the inclusion of orders that yield Flag 7 when determining the liquidity adding rebate under its tiered pricing structure. The Exchange notes that its proposal conforms to an existing practice and does not modify the rebates or fees that the Exchange provides its Members for achieving tier-based pricing. The Exchange has historically in practice and will continue to include routed shares when calculating a Member's ADV by including orders that yield Flag 7 when determining the liquidity adding rebate under its tiered pricing structure. Other than this correction, which resolves a conflict in the Fee Schedule, the remainder of the definition of ADV would remain unchanged. Lastly, the Exchange also believes that these proposed amendments are non-discriminatory because they apply uniformly to all Members.
The Exchange believes its proposed amendments to its Fee Schedule would not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposed change represents a significant departure from previous pricing offered by the Exchange or pricing offered by the Exchange's competitors. Additionally, Members may opt to disfavor EDGX's pricing if they believe that alternatives offer them better value. Accordingly, the Exchange does not believe that the proposed change will impair the ability of Members or competing venues to maintain their competitive standing in the financial markets.
The Exchange believes that its proposal to delete Flag RC in its Fee Schedule would not affect intermarket nor intramarket competition because this change is not designed to amend any fee or rebate or alter the manner in which the Exchange assesses fees or calculates rebates. It is simply proposed in response to NSX announcement that it will cease market operations and its last day of trading will be Friday, May 30, 2014.
The Exchange believes that correcting an inadvertent error in the definition of ADV would not impose a burden on intermarket or intramarket competition because it simply conforms to an existing practice by resolving a conflict in the Fee Schedule and does not modify the rebates or fees that the Exchange provides its Members for achieving tier-based pricing. The Exchange has historically in practice and will continue to include routed shares when calculating a Member's ADV by including orders that yield Flag 7 when determining the liquidity adding rebate under its tiered pricing structure. Other than this correction, the
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any unsolicited written comments from Members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
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 an email to
• Send paper comments in triplicate to 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.
On April 11, 2014, The NASDAQ Stock Market LLC (“Exchange” or “Nasdaq”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to list and trade Shares pursuant to Nasdaq Rule 5735, which governs the listing and trading of Managed Fund Shares.
The Shares will be offered by the Trust, which is organized as a Massachusetts business trust and is registered with the Commission as an investment company.
The investment objective of the Fund will be to seek current income, consistent with preservation of capital and daily liquidity. Under normal market conditions,
The Fund intends to achieve its investment objective by investing, under normal market conditions, at least 80% of its net assets in a portfolio of U.S. dollar-denominated Fixed Income Securities issued by U.S. and non-U.S. public- and private-sector entities. At least 80% of the Fund's net assets will be invested in Fixed Income Securities that are, at the time of purchase, investment grade. Fixed Income Securities will include the following types of fixed- and variable-rate debt securities: corporate
Under normal market conditions, the Fund's duration
Under normal market conditions, the Fund will invest primarily in the Fixed Income Securities described above to meet its investment objective. In addition, the Fund may invest up to 20% of its net assets in floating rate loans. The floating rate loans in which the Fund will invest will represent amounts borrowed by companies or other entities from banks and other lenders and a significant portion of such floating rate loans may be rated below investment grade or unrated. Floating rate loans held by the Fund may be senior or subordinate obligations of the borrower and may or may not be secured by collateral.
The Fund will not invest 25% or more of the value of its total assets in securities of issuers in any one industry. This restriction does not apply to (a) obligations issued or guaranteed by the U.S. government, its agencies or instrumentalities or (b) securities of other investment companies.
The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), including Rule 144A securities deemed illiquid by the Adviser. The Fund will monitor its portfolio liquidity on an ongoing basis to determine whether, in light of current circumstances, an adequate level of liquidity is being maintained, and will consider taking appropriate steps in order to maintain adequate liquidity if, through a change in values, net assets, or other circumstances, more than 15% of the Fund's net assets are held in illiquid assets. Illiquid assets include securities subject to contractual or other restrictions on resale and other instruments that lack readily available markets as determined in accordance with Commission staff guidance.
The Fund will not invest in non-U.S. equity securities.
After careful review, the Commission finds that the proposed rule change, as modified by Amendment No. 1 thereto, is consistent with the requirements of Section 6 of the Act
The Commission finds that the proposal to list and trade the Shares on the Exchange is consistent with Section 11A(a)(1)(C)(iii) of the Act,
The Commission believes that the proposal to list and trade the Shares is reasonably designed to promote fair disclosure of information that may be necessary to price the Shares appropriately and to prevent trading when a reasonable degree of transparency cannot be assured. The NAV of the Shares generally will be calculated once daily Monday through Friday as of the close of regular trading on the New York Stock Exchange, generally 4:00 p.m., Eastern time. On each business day, before commencement of trading in Shares in the Regular Market Session
Further, regarding trading in the Shares and the exchange-traded securities held by the Fund, the Commission notes that the Financial Industry Regulatory Authority (“FINRA”) will communicate as needed on behalf of the Exchange
In support of this proposal, the Exchange has made representations, including:
(1) The Shares will conform to the initial and continued listing criteria under Nasdaq Rule 5735.
(2) The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions.
(3) The Exchange represents that trading in the Shares will be subject to the existing trading surveillances, administered by FINRA on behalf of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws and that these procedures are adequate to properly monitor Exchange trading of the Shares in all trading sessions and to deter and detect violations of Exchange rules and applicable federal securities laws.
(4) Prior to the commencement of trading, the Exchange will inform its members in an Information Circular of the special characteristics and risks associated with trading the Shares. Specifically, the Information Circular will discuss the following: (a) The procedures for purchases and redemptions of Shares in Creation Units (and that Shares are not individually redeemable); (b) Nasdaq Rule 2310, which imposes suitability obligations on Nasdaq members with respect to recommending transactions in the Shares to customers; (c) how information regarding the Intraday Indicative Value is disseminated; (d) the risks involved in trading the Shares during the Pre-Market and Post-Market Sessions when an updated Intraday Indicative Value will not be calculated or publicly disseminated; (e) the requirement that members deliver a prospectus to investors purchasing newly issued Shares prior to or concurrently with the confirmation of a transaction; and (f) trading information.
(5) For initial and continued listing, the Fund will be in compliance with Rule 10A-3 under the Act.
(6) While the Fund is permitted to invest without restriction in corporate bonds, the Adviser expects that, under normal market conditions, generally, with respect to at least 75% of the Fund's portfolio, a corporate bond will have, at the time of original issuance, $100 million or more par amount outstanding to be considered as an eligible investment.
(7) The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), including Rule 144A securities deemed illiquid by the Adviser.
(8) The Fund will limit its investments in asset-backed securities and non-agency mortgage-backed securities (in the aggregate) to 20% of its net assets.
(9) The Fund will not invest in non-U.S. equity securities.
(10) A minimum of 100,000 Shares will be outstanding at the commencement of trading.
For the foregoing reasons, the Commission finds that the proposed rule change is consistent with Section 6(b)(5) of the Act
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 (the “Act”),
The Exchange proposes to amend its fees and rebates applicable to Members
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 its Fee Schedule to: (i) Delete Flag RC, which routes to the NSX and adds liquidity; and (ii) make a corrective change to the definition of ADV to state that ADV includes shared routed by the Exchange.
The Exchange proposes to amend its Fee Schedule to delete Flag RC, which routes to the NSX and adds liquidity, in response to the NSX's announcement that it will cease market operations and its last day of trading will be Friday, May 30, 2014.
The Exchange proposes to make a corrective change to the definition of ADV to state that a Member's ADV
The Exchange's Fee Schedule currently states that certain routed flags are considered when determining the liquidity adding rebate that the Exchange will provide to Members based on its tiered pricing structure.
The Exchange proposes to implement these amendments to its Fee Schedule on June 2, 2014
The Exchange believes that the proposed rule change is consistent with the objectives of Section 6 of the Act,
The Exchange believes that its proposal to delete Flag RC in its Fee Schedule represents an equitable allocation of reasonable dues, fees, and other charges among Members and other persons using its facilities. The proposed change is in response to NSX's announcement that it will cease market operations and its last day of trading will Friday, May 30, 2014.
The Exchange believes that correcting an inadvertent error in the definition of ADV with regard to routed orders is reasonable because it will increase the level of transparency on the Exchange's Fee Schedule and improve the Exchange's ability to effectively convey the criteria necessary to achieve tier-based pricing and resolve a conflict in the Fee Schedule between the definition of ADV and the inclusion of orders that certain routed flags when determining the liquidity adding rebate under its tiered pricing structure. The Exchange notes that its proposal conforms to an existing practice and does not modify the rebates or fees that the Exchange provides its Members for achieving tier-based pricing. The Exchange has historically in practice and will continue to include routed shares when calculating a Member's ADV by including orders that yield certain routed flags when determining the liquidity adding rebate under its tiered pricing structure. Other than this correction, which resolves a conflict in the Fee Schedule, the remainder of the definition of ADV would remain unchanged. Lastly, the Exchange also believes that these proposed amendments are non-discriminatory because they apply uniformly to all Members.
The Exchange believes its proposed amendments to its Fee Schedule would not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposed change represents a significant departure from previous pricing offered by the Exchange or pricing offered by the Exchange's competitors. Additionally, Members may opt to disfavor EDGA's pricing if they believe that alternatives offer them better value. Accordingly, the Exchange does not believe that the proposed change will impair the ability of Members or competing venues to maintain their competitive standing in the financial markets.
The Exchange believes that its proposal to delete Flag RC in its Fee Schedule would not affect intermarket nor intramarket competition because this change is not designed to amend any fee or rebate or alter the manner in which the Exchange assesses fees or
The Exchange believes that correcting an inadvertent error in the definition of ADV would not impose a burden on intermarket or intramarket competition because it simply conforms to an existing practice by resolving a conflict in the Fee Schedule and does not modify the rebates or fees that the Exchange provides its Members for achieving tier-based pricing. The Exchange has historically in practice and will continue to include routed shares when calculating a Member's ADV by including orders that yield certain routed flags when determining the liquidity adding rebate under its tiered pricing structure. Other than this correction, the remainder of the definition of ADV would remain unchanged.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any unsolicited written comments from Members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
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 an email to
• Send paper comments in triplicate to 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”)
The Exchange filed a proposal for the BATS Options Market (“BATS Options”) to extend through December 31, 2014, the Penny Pilot Program (“Penny Pilot”) in options classes in certain issues (“Pilot Program”) previously approved by the Commission.
The text of the proposed rule change is available at the Exchange's 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 Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
The purpose of this filing is to extend the Penny Pilot, which was previously approved by the Commission, through December 31, 2014, and to provide a revised date for adding replacement issues to the Pilot Program. The Exchange proposes that any Pilot Program issues that have been delisted may be replaced on the second trading day following July 1, 2014. The replacement issues will be selected based on trading activity for the six month period beginning December 1, 2013, and ending May 31, 2014.
The Exchange represents that the Exchange has the necessary system capacity to continue to support operation of the Penny Pilot. The Exchange believes the benefits to public customers and other market participants who will be able to express their true prices to buy and sell options have been demonstrated to outweigh the increase in quote traffic.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. In this regard, the Exchange notes that the rule change is being proposed in order to continue the Pilot Program, which is a competitive response to analogous programs offered by other options exchanges. The Exchange believes this proposed rule change is necessary to permit fair competition among the options exchanges.
The Exchange has neither solicited nor received written comments on the proposed rule change.
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) normally does not become operative prior to 30 days after the date of the filing.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act.
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 Secretary, Securities and Exchange
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 (the “Act”),
The ISE proposes to amend the Schedule of Fees to increase (1) the route-out fee applicable to Priority Customer orders, and (2) the Priority Customer taker fee in Select Symbols for members that do not meet a new total affiliated Priority Customer ADV threshold. The text of the proposed rule change is available on the Exchange's Web site (
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 purpose of the proposed rule change is to amend the Schedule of Fees to increase (1) the route-out fee applicable to Priority Customer
The Exchange charges a fee of $0.40 per contract and $0.55 per contract for executions of Priority Customer and Professional Customer
The Exchange currently assesses per contract transaction fees and provides rebates to market participants that add liquidity to or remove liquidity from the Exchange (“maker/taker fees and rebates”) in Select Symbols. The taker fee for removing liquidity in Select Symbols is $0.42 per contract for Market Maker
In connection with the above change, the Exchange further proposes to include the definition of total affiliated Priority Customer ADV in a separate footnote.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes the proposed Priority Customer route-out fee is reasonable and equitable as it provides the Exchange the ability to recover costs associated with using unaffiliated broker-dealers to route Priority Customer orders to other exchanges for linkage executions. The Exchange notes that a number of other exchanges currently charge a variety of routing related fees associated with orders that are subject to linkage handling. The Exchange also believes that the proposed fees are not unfairly discriminatory because these fees would be uniformly applied to all Priority Customer orders. In addition, the fees charged for Priority Customer linkage executions will continue to be lower than the fees charged to Professional Customer orders.
The Exchange is proposing to adopt a volume-based taker fee structure for Priority Customer orders in Select Symbols. Under the proposed structure, members that execute a Priority Customer ADV of 200,000 contracts or more in a calendar month will be eligible for a discounted taker fee. The Exchange currently provides a similar incentive as part of its Market Maker Plus program for members whose affiliates execute a total affiliated Priority Customer ADV of at least 200,000 contracts in a given month. The Exchange believes that charging lower fees to Priority Customer orders from members that execute more Priority Customer volume on the ISE is reasonable and equitable as this will attract additional Priority Customer order flow to the Exchange, which will ultimately benefit all market participants that trade on the ISE. The Exchange also believes that the new tiered taker fee is not unfairly discriminatory because all members can achieve the lower fee for their Priority Customer orders by executing the required Priority Customer volume on the ISE. Furthermore, while the Exchange is increasing the taker fee in Select Symbols for Priority Customer orders executed by members that do not meet the new volume threshold, these members will continue to pay taker fees for their Priority Customer orders that are lower than the fees charged to other market participants on the ISE, and that are within the range of fees assessed by other options exchanges.
Finally, as noted above, the Exchange is proposing to move the definition of total affiliated Priority Customer ADV to a separate footnote. The Exchange believes that this non-substantive change is appropriate to eliminate investor confusion since this definition will now apply to Priority Customer taker fees as discussed here.
The Exchange notes that it has determined to charge fees in Mini Options at a rate that is 1/10th the rate of fees and rebates the Exchange provides for trading in Standard Options. The Exchange believes it is reasonable and equitable and not unfairly discriminatory to assess lower fees to provide market participants an incentive to trade Mini Options on the Exchange. The Exchange believes the proposed fees are reasonable and equitable in light of the fact that Mini Options have a smaller exercise and assignment value, specifically 1/10th that of a standard option contract, and, as such, is providing fees for Mini Options that are 1/10th of those applicable to Standard Options.
In accordance with Section 6(b)(8) of the Act,
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any unsolicited written comments from members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
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 an email to
• Send paper comments in triplicate to 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
NASDAQ proposes to modify Chapter XV, entitled “Options Pricing,” at Section 2 governing pricing for NASDAQ members using the NASDAQ Options Market (“NOM”), NASDAQ's facility for executing and routing standardized equity and index options. Specifically, NOM proposes amending the NOM Market Maker
While the Exchange has designated the proposal as effective upon filing, the Exchange has designated that the change is operative on June 2, 2014.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
NASDAQ proposes to amend Chapter XV, Section 2 regarding the Tier 6 NOM Market Maker Rebates to Add Liquidity in Penny Pilot Options, to add another methodology by which a Participant can earn the rebate. NASDAQ proposes the amendment in order to continue to incentivize Participants to select NOM as a venue when directing order flow.
The Exchange currently pays NOM Market Maker Rebates to Add Liquidity based on a six tier rebate structure, which is found in Chapter XV, Section 2(1), as follows:
For purposes of qualifying for a NOM Market Maker Penny Pilot Options Rebate to Add Liquidity tier, the Exchange today uses a metric that is a percentage of total industry customer equity and exchange traded fund (“ETF”) option average daily volume (“ADV”) contracts per day in a month.
The Exchange proposes to amend the Tier 6 rebate to add an alternative to the current metric. Specifically, in addition to the current metric of above 0.80% of total industry customer equity and ETF option ADV where the NOM Market Maker also qualifies for the Tier 7 or Tier 8 Customer and/or Professional Rebate to Add Liquidity in Penny Pilot Options,
With the proposed amendment, the Exchange would pay a Tier 6 $0.42 per contract rebate where a Participant adds NOM Market Maker liquidity in Penny Pilot Options and/or Non-Penny Pilot Options above 0.80% of total industry customer equity and ETF option ADV contracts per day in a month and qualifies for the Tier 7 or Tier 8 Customer and/or Professional Rebate to Add Liquidity in Penny Pilot Options, or Participant adds NOM Market Maker liquidity in Penny Pilot Options and/or Non-Penny Pilot Options above 0.90% of total industry customer equity and ETF option ADV contracts per day in a month. The Exchange is not amending the current qualification for the Tier 6
In addition, the Exchange is proposing to delete an extraneous period in Tier 5, and thereby conform the punctuation in Tiers 1 through 6 of the NOM Market Maker Rebates to Add Liquidity in Penny Pilot Options.
The Exchange would continue to incentivize Participants, with NOM Market Maker rebate Tiers 1 through 6 as amended, to provide liquidity by paying specified rebates to those Participants that add NOM Market Maker liquidity in Penny Pilot Options and/or Non-Penny Pilot Options according to percentage metrics keyed to industry customer equity and ETF option average ADV contracts per day in a month.
NASDAQ believes that its proposal to amend its Pricing Schedule is consistent with Section 6(b) of the Act
The Exchange's goal is to modify percentage eligibility thresholds where a Participant adds NOM Market Maker liquidity in order to continue to encourage market participants to direct a greater amount of NOM Market Maker liquidity to the Exchange. The Exchange's proposal does not eliminate rebates or the ability for market participants to earn rebates, but rather incorporates an additional way to earn rebates as noted herein.
The Exchange's proposal to amend Tier 6 of the NOM Market Maker Rebate to Add Liquidity in Penny Pilot Options is reasonable, equitable and not unfairly discriminatory for the reasons noted below.
The Exchange's proposal to adopt a new Tier 6 metric for Participants that add the highest level of NOM Market Maker liquidity in Penny Pilot Options and/or Non-Penny Pilot Options above 0.90% of total industry customer equity and ETF option ADV contracts per day in a month is equitable and not unfairly discriminatory because all eligible Participants that qualify for the additional Tier 6 NOM Market Maker Rebate to Add Liquidity metric will be uniformly paid the rebate.
The Exchange would continue to incentivize Participants, with Tiers 1 through 6 NOM Market Maker Penny Pilot Options Rebates to Add Liquidity, as amended, to provide liquidity by paying specified rebates to those Participants that add NOM Market Maker liquidity in Penny Pilot Options and/or Non-Penny Pilot Options according to percentage metrics keyed to industry customer equity and ETF option average ADV contracts per day in a month. The proposed percentage metrics are dynamic in nature in that they reference total industry options contracts per day (rather than a static number of contracts per day),
In addition, the Exchange believes it is reasonable to continue to use percentage metrics keyed to industry customer equity and ETF option average ADV contracts per day in a month because that is a benchmark that Participants are comfortable with in respect to Customer and Professional liquidity. Moreover, the Exchange believes that industry customer volume is a fair metric because it does not have the periodic spikes that may occur due to floor trading. Because NOM is an electronic market place with no trading floor, the Exchange believes that an industry volume metric is fair and reasonable.
NASDAQ 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.
The Exchange believes that adding an additional percentage eligibility metric in Tier 6 for Participants that bring the largest amount of liquidity should encourage Participants to direct additional NOM Market Maker order flow to the Exchange, and will dovetail with the existing metric in Tier 6.
Added liquidity benefits all market participants by providing more trading opportunities, which attracts market participants to the Exchange. An increase in the activity of these market participants in turn facilitates tighter spreads, which may cause an additional corresponding increase in order flow from other market participants. The Exchange believes that encouraging Participants to add NOM Market Maker liquidity creates competition among options exchanges because the Exchange believes that the rebates may cause market participants to select NOM as a venue to send order flow. The Exchange is continuing to offer rebates at specified percentage metrics for NOM Market Maker order flow being executed at the Exchange, which additional order flow should benefit other market participants.
The Exchange operates in a highly competitive market comprised of twelve U.S. options exchanges in which many sophisticated and knowledgeable market participants can readily and do send order flow to competing exchanges if they deem fee levels or rebate incentives at a particular exchange to be excessive or inadequate. These market forces support the Exchange belief that the rebate structure and tiers as amended are competitive with rebates and tiers in place on other exchanges. The Exchange believes that this competitive marketplace continues to impact the rebates present on the Exchange today and substantially influences the proposals set forth above.
No written comments were either solicited or received.
The foregoing rule change has become effective pursuant to Section
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 an email to
• Send paper comments in triplicate to 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to amend the fee schedule applicable to Members
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange 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 Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to modify the “Options Pricing” section of its fee schedule effective immediately, in order to amend a rebate and add two new tiers for Customer
The Exchange currently provides rebates for Customer orders that add liquidity to the BATS Options order book in Penny Pilot Securities pursuant to a tiered pricing structure, as described below, including a cross-asset tier, which provides enhanced rebates to
The Exchange is proposing to reduce the per contract rebate for the Lower Tier from $0.45 to $0.25. The Exchange is also proposing to create a new tier between the Lower Tier and the Second Tier in which a Member that has an ADV equal to or greater than 0.05% of average TCV, but less than 0.30% of average TCV will receive $0.45 per contract, the same rebate previous available in the Lower Tier. Finally, the Exchange is proposing to add an additional cross-asset tier in which a Member will receive $0.50 per contract where the Member has an ADV equal to or greater than 0.80% of average TCV and has on BATS Equities an ADAV equal to or greater than 0.50% of average TCV (the “New Cross-Asset Tier”).
The Exchange proposes to implement these amendments to its fee schedule on June 2, 2014.
The Exchange believes that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6 of the Act.
Volume-based rebates and fees such as the ones maintained by BATS Options, and as amended by this proposal, have been widely adopted in the cash equities markets, and are reasonable and equitable because they are open to all Members on an equal basis and provide additional benefits or discounts that are reasonably related to the value to an exchange's market quality associated with higher levels of market activity, such as higher levels of liquidity provision and/or growth patterns, and introduction of higher volumes of orders into the price and volume discovery processes. Accordingly, the Exchange believes that the proposed changes to the Exchange's tiered pricing structure and incentives are not unfairly discriminatory because they are consistent with the overall goals of enhancing market quality. Similarly, the Exchange believes that continuing to base its tiered fee structure on overall TCV, rather than a static number of contracts irrespective of overall volume in the options industry, is a fair and equitable approach to pricing.
The Exchange notes that while the rebate for the Lower Tier is being reduced (from $0.45 to $0.25 per contract) such proposed new rebate is reasonable, fair and equitable in that it is the same as the rebate offered by NYSE Arca, Inc. and is $0.05 greater than rebate offered by the Nasdaq Stock Market LLC for Customer orders that add liquidity in Penny Pilot Securities that do not meet any other volume tiers. Further, the Exchange believes the reduction of the rebate for the Lower Tier is reasonable, fair and equitable because the Exchange is also proposing to introduce a new volume tier between the Lower Tier and the Second Tier with a relatively low volume threshold, where a Member will receive a $0.45 rebate per contract for Customer orders in Penny Pilot Securities where the Member has an ADV equal to or greater than 0.05% of average TCV. Thus, all Members with an ADV equal to or greater than 0.05%, but less than 0.30% of average TCV will receive the same rebate that they would have previously received pursuant to the Lower Tier for Customer orders that add liquidity in Penny Pilot Securities. The Exchange also believes that the new volume tier between the Lower Tier and Second Tier is reasonable, fair and equitable because it will encourage Members to add liquidity on BATS Options and because such Members will qualify for rebates pursuant to the new volume tier at a relatively low volume threshold. The Exchange further believes that the proposed amendment to rebates for the Lower Tier and the addition of a new tier between the Lower Tier and the Second Tier are fair and equitable and not unreasonably discriminatory because they will apply uniformly to all Members and are consistent with the overall goal of enhancing market quality on BATS Options as described above with respect to volume-based rebates and fees.
The Exchange's proposed New Cross-Asset Tier is reasonable, fair and equitable because it provides additional flexibility for Members to receive the highest possible rebate for Customer orders that add liquidity in Penny Pilot Securities. Compared to the Cross-Asset Tier, Members must meet a lower threshold on BATS Options (0.80% vs. 0.90%), but a higher threshold for BATS Equities (0.50% vs. 0.25%) in order to qualify for the New Cross-Asset Tier rebate of $0.50. Thus, the Exchange believes that the New Cross-Asset Tier is reasonable, fair and equitable because it will provide Members with a different volume profile on BATS Options and BATS Equities with the opportunity to qualify for the $0.50 per contract rebate, while simultaneously encouraging more Members to add liquidity on both BATS Equities and BATS Options. Further, the Exchange believes that the addition of
The Exchange does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act, as amended. With respect to the proposed new tiers and rebates, the Exchange does not believe that any such changes burden competition, but instead, enhance competition, as they are intended to increase the competitiveness of and draw additional volume to BATS Options, and, in the case of the New Cross-Asset Tier, also to BATS Equities. The Exchange also believes that the changes to the tiers as a whole will enhance competition because they are similar to pricing tiers currently available on other exchanges. As stated above, the Exchange notes that it operates in a highly competitive market in which market participants can readily direct order flow to competing venues if the deem fee structures to be unreasonable or excessive. As such, the proposal is a competitive proposal that is intended to add additional liquidity to the Exchange, which will, in turn, benefit the Exchange and all Exchange participants.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
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 an email to
• Send paper comments in triplicate to 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.
Pursuant to Section 19(b)(1)
The Exchange proposes to proposes to [sic] amend the NYSE Arca Equities Schedule of Fees and Charges for Exchange Services (“Fee Schedule”) to add an additional requirement to qualify for Step Up Tier 3. The Exchange proposes to implement the fee change effective June 1, 2014. The text of the proposed rule change is available on the Exchange's 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
The Exchange proposes to amend the Fee Schedule to add an additional requirement to qualify for Step Up Tier 3, which was introduced into the Fee Schedule effective February 1, 2014.
Step Up Tier 3 in the Fee Schedule is applicable to an ETP Holder, including a Market Maker, that on a daily basis, measured monthly, directly executes providing volume (“Adding ADV”) during the billing month that is both (i) at least 0.20% of U.S. consolidated average daily volume (“U.S. CADV”) for the billing month and (ii) at least 0.125% taken as a percentage of U.S. CADV for the billing month over the ETP Holder's December 2013 Adding ADV taken as a percentage of U.S. CADV in December 2013 (“Baseline % CADV”).
A qualifying ETP Holder is eligible to receive a credit of $0.0004 per share for (i) Adding ADV in Tape A securities during the billing month taken as a percentage of U.S. CADV in Tape A securities in the billing month in excess of the Baseline % CADV in Tape A securities and (ii) Adding ADV in Tape C securities during the billing month taken as a percentage of U.S. CADV in Tape C securities in the billing month in excess of the Baseline % CADV in Tape C securities.
The Exchange proposes that, in addition to the existing two requirements described above, to qualify for Step Up Tier 3 an ETP Holder would be required to directly execute Adding ADV during the billing month that is at least 40% over the ETP Holder's Baseline % CADV as a percentage of U.S. CADV for the billing month.
However, and for further example, if the ETP Holder's Baseline % CADV instead was 0.60%, the ETP Holder's Adding ADV during the billing month would need to be at least 0.84% for the billing month. If U.S. CADV for the billing month was 7 billion shares, the ETP Holder's Adding ADV during the billing month would need to be at least 58.8 million shares (
No other changes to Step Up Tier 3, or the corresponding credit, would result from this proposed change.
The proposed change is not otherwise intended to address any other issues, and the Exchange is not aware of any problems that ETP Holders would have in complying with the proposed change.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
The existing requirement of Adding ADV during the billing month that is at least 0.20% of U.S. CADV establishes a minimum for any ETP Holder in order to qualify for Step Up Tier 3. The existing requirement of Adding ADV during the billing month of at least 0.125% taken as a percentage of U.S. CADV for the billing month over the ETP Holder's Baseline % CADV establishes a minimum amount that the ETP Holder must “step up” during the billing month, based on U.S. CADV during the billing month. In other words, as U.S. CADV during a particular billing month increases, the Adding ADV required of an ETP Holder would similarly increase (conversely, required Adding ADV would decrease if U.S. CADV during a particular billing month decreases). The proposed new requirement of Adding ADV during the billing month that is at least 40% over the ETP Holder's Baseline % CADV as a percentage of U.S. CADV for the billing month is reasonable because it would establish a minimum amount that each ETP Holder must “step up” during the billing month, but based
The Exchange believes that this proposed new requirement is also reasonable because it would further contribute to the goal of Step Up Tier 3—namely, encouraging ETP Holders to send additional orders to the Exchange for execution in order to qualify for an incrementally higher credit for such executions in Tape A and Tape C securities that add liquidity on the Exchange.
The Exchange also believes that the proposed additional requirement to qualify for Step Up Tier 3 credit is equitable and not unfairly discriminatory because it would incentivize ETP Holders to submit orders to the Exchange and would result in a credit that is reasonably related to an exchange's market quality that is associated with higher volumes. Moreover, like existing pricing on the Exchange that is tied to ETP Holder volume levels, the Exchange believes that the proposed qualifying threshold for Step Up Tier 3 is equitable and not unfairly discriminatory because it would be available for all ETP Holders, including Market Makers, on an equal and non-discriminatory basis. It is also equitable and not unfairly discriminatory that an ETP Holder with zero Adding ADV in December 2013 (
Finally, the Exchange believes that it is subject to significant competitive forces, as described below in the Exchange's statement regarding the burden on competition.
For these reasons, the Exchange believes that the proposal is consistent with the Act.
In accordance with Section 6(b)(8) of the Act,
Also, the Exchange does not believe that the proposed change will impair the ability of ETP Holders or competing order execution venues to maintain their competitive standing in the financial markets. In this regard, the Exchange notes that existing pricing tiers of other exchanges similarly provide for credits for market participants that provide certain levels of liquidity on those exchanges.
Finally, the Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive or rebate opportunities available at other venues to be more favorable. In such an environment, the Exchange must continually adjust its fees and rebates to remain competitive with other exchanges and with alternative trading systems that have been exempted from compliance with the statutory standards applicable to exchanges. Because competitors are free to modify their own fees and credits in response, and because market participants may readily adjust their order routing practices, the Exchange believes that the degree to which fee changes in this market may impose any burden on competition is extremely limited. As a result of all of these considerations, the Exchange does not believe that the proposed changes will impair the ability of member organizations or competing order execution venues to maintain their competitive standing in the financial markets.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to Section 19(b)(3)(A)
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B)
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 an email to
• Send paper comments in triplicate to 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to amend the fees applicable to securities listed on the Exchange pursuant to BATS Rule 14.13. Changes to the Exchange's fees pursuant to this proposal are effective upon filing.
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange 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 Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
On August 30, 2011, the Exchange received approval of rules applicable to the qualification, listing, and delisting of companies on the Exchange,
Currently, Rule 14.13(a)(A)(1)(C) provides that the entry fee for an ETP is $10,000, a fee that is assessed on the date of listing on the Exchange, except for a $5,000 non-refundable application fee which must be submitted along with the initial listing application. The Exchange proposes to instead charge a reduced entry fee of $5,000, which will continue to be non-refundable and due upon submission of the initial listing application. Consistent with current Rule 14.13 the Exchange is not proposing to charge an entry fee for transfer listings.
The Exchange is also proposing to introduce lower annual fees for ETPs. Currently, Rule 14.13 provides that the issuer of an ETP shall pay an annual fee of $35,000 for funds initially listed on the Exchange. Rule 14.13 provides that the issuer of an ETP that is a transfer listing shall pay an annual fee of $15,000. The Exchange is proposing to continue to charge $35,000 per year to the issuer of an ETP that is participating in the CLP Program. For all issuers of ETPs that are not participating in the CLP Program, including transfer listings, the Exchange proposes to charge the issuer on a quarterly basis based on the ETPs consolidated average daily volume (the “CADV”), as defined below, during the quarter preceding the billing date.
As proposed, CADV is calculated based on the three calendar months preceding the month for which the fees apply, meaning that when calculating the rebates that apply to a particular ETP, the CADV will be based on the three calendar months prior to the current trading month. For example, in calculating the annual fee that will be billable to the issuer of an ETP on the first day of the third quarter, the Exchange will look to the average daily volume reported for the ETP by all exchanges and trade reporting facilities to a consolidated transaction reporting plan for the second quarter, or April, May, and June. If that ETP was an initial listing on BATS (not a transfer listing from another listing market) and was listed beginning on May 15, the calculation of CADV would include all days from April 1 through May 14 with zero volume for each trading day. For transfer listings, the determination of the annual fees applicable to the ETP in the third quarter will be based on the CADV for the second quarter, regardless of where the ETP was listed during that period.
As noted above, the Exchange proposes to amend Rule 14.13 in order to make clear that the issuer of an ETP that participates in the CLP Program will continued to pay the Exchange an annual fee of $35,000.
Finally, the Exchange is proposing to correct a typographical error in the rule text. Specifically, the Exchange is proposing to amend the second sub-paragraph “(a)” in Rule 14.13 to “(b)” in order to make the rule more easily understandable.
The Exchange proposes to implement these amendments to its fees on June 2, 2014.
The Exchange believes that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6 of the Act.
The Exchange is proposing a tiered pricing structure for ETPs listed on the Exchange based on CADV that will significantly reduce listing fees for all new issuers, with the potential for free listing, which the Exchange believes are equitable and non-discriminatory because the tiers will be applied equally to all ETPs listed on the Exchange, including transfer listings. The Exchange also believes that continuing to charge $35,000 annually for ETPs that continue to participate in the CLP Program is equitable and non-discriminatory because the costs associated with operating the CLP Program are significantly higher than the anticipated costs associated with the new lead market maker program (the “LMM Program”), into which newly listed ETPs will be automatically enrolled. Further, ETPs participating in the CLP Program may opt out of the CLP Program at any time in order to participate in the LMM Program and be charged the lower quarterly fees. Similarly, the Exchange believes that, while a transfer listing could possibly be charged a higher annual fee under the proposal ($18,000 vs. $15,000), the proposed changes are equitable and non-discriminatory because the pricing will be applied equally to all ETP listings, including transfer listings, and ETP transfer listings may also be eligible for reduced fees. Additionally, as described below, the annual fees are generally based on the cost to the Exchange associated with listing. The Exchange notes that it does not currently have any transfer listings and thus there are no BATS-listed ETPs that are eligible for continued annual fees of $15,000, as provided in current Rule 14.13, meaning that no existing ETP listings will be subject to a change in pricing and that any ETP that transfers to the Exchange in the future will have advanced notice of the proposed pricing.
The Exchange believes that it is equitable, reasonable, and non-discriminatory to charge increased listing fees to ETPs as their CADV increases. Under the LMM Program, the Exchange plans to offer enhanced rebates to any registered lead market maker for executions where such lead market maker has added displayed liquidity in a BATS-listed ETP for which they are designated as lead market maker, provided that they must meet specified quoting requirements in such BATS-listed ETP. The Exchange notes that as part of these enhanced rebates, it is planning to provide gradually
The Exchange also believes that it is equitable, reasonable, and non-discriminatory to provide listings free of charge to ETPs with CADV exceeding 400,000. As a general matter, ETPs that are better known and well-established are frequently more actively traded, liquid securities. The Exchange believes that the benefits to both the Exchange and other Exchange constituents of attracting and retaining such ETPs to list on the Exchange justifies the Exchange waiving the listing fees for these issuers. As it relates to other issuers, the ability of the Exchange to attract well-known, recognizable, and successful ETPs on the Exchange will help the Exchange to establish its status and reputation as a
The Exchange believes it is reasonable and equitable to assess annual fees on a pro-rated quarterly basis instead of an annual basis based on the listing date of an ETP. In particular, the Exchange believes that quarterly billing in prorated amounts will allow an issuer's bill to more accurately reflect an ETP's current CADV.
The Exchange also believes that lowering the initial listing fee from $10,000 to $5,000 for ETPs is reasonable and equitable because it will result in lower initial costs to all ETP issuers.
Finally, the Exchange believes that correcting the typographical error to the numbering of the subparagraphs of Rule 14.13 is reasonable and equitable because it will make the rule text more easily understandable.
The Exchange does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act, as amended. With respect to the proposed new pricing for the listing of ETPs, the Exchange does not believe that the changes burden competition, but instead, enhance competition, as it is intended to increase the competitiveness of the Exchange's listings program. The Exchange also believes the proposed change would enhance competition because it brings ETP listings prices closer to those currently offered by both Arca and Nasdaq. The proposed changes are generally intended to lower the Exchange's listing fees and make these fees more reflective of an ETP's trading activity, which the Exchange believes will further help it compete against the other listing markets. As such, the proposal is a competitive proposal that is intended to attract additional ETP listings, which will, in turn, benefit the Exchange and all other BATS-listed ETPs.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
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 an email to
• Send paper comments in triplicate to 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 Social Security Administration (SSA) publishes a list of information collection packages requiring clearance by the Office of Management and Budget (OMB) in compliance with Public Law 104-13, the Paperwork Reduction Act of 1995, effective October 1, 1995. This notice includes three revisions and one extension of OMB-approved information collections.
SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology. Mail, email, or fax your comments and recommendations on the information collection(s) to the OMB Desk Officer and SSA Reports Clearance Officer at the following addresses or fax numbers.
SSA submitted the information collections below to OMB for clearance. Your comments regarding the information collections would be most useful if OMB and SSA receive them 30 days from the date of this publication. To be sure we consider your comments, we must receive them no later than July 18, 2014. Individuals can obtain copies of the OMB clearance packages by writing to
1. Representative Payee Report—Adult, Representative Payee Report—Child, Representative Payee Report—Organizational Representative Payees—20 CFR 404.635, 404.2035, 404.2065, and 416.665—0960-0068. When SSA determines it is not in an Old Age, Survivors, and Disability Insurance (OASDI) or Supplemental Security Income (SSI) recipient's best interest to receive Social Security payments directly, the agency will designate a representative payee for the recipient. The representative payee can be: (1) A family member; (2) a non-family member who is a private citizen and is acquainted with the beneficiary; (3) an organization; (4) a state or local government agency; or (5) a business. In the capacity of representative payee, the person or organization receives the SSA recipient's payments directly and manages these payments. As part of its stewardship mandate, SSA must ensure the representative payees are properly using the payments they receive for the recipients they represent. The agency annually collects the information necessary to make this assessment using the SSA-623, Representative Payee Report—Adult, SSA-6230, Representative Payee Report—Child, SSA-6234, Representative Payee Report—Organizational Representative Payees, and through the electronic internet application Internet Representative Payee Accounting (iRPA). The respondents are representative payees of OASDI and SSI recipients.
2. Statement of Income and Resources—20 CFR 416.207, 146.301-416.310, 416.704, and 416.708—0960-0124. SSA collects information about income and resources for SSI claims and redeterminations on the SSA-8010-BK. SSA uses the information to make initial or continuing eligibility determinations for SSI claimants or recipients who are subject to deeming. The respondents are persons whose income and resources SSA may deem (consider to be available) to SSI applicants or recipients.
3. Authorization to Obtain Earnings Data From the Social Security Administration—0960-0602. On occasion, public and private organizations and agencies, need to obtain detailed earnings information about specific Social Security number (SSN) holding wage earners for business purposes (e.g. pension funds, State agencies, etc.). Respondents use Form SSA-581 to identify the SSN holder whose information they are requesting, and provide authorization from the SSN holder, when applicable. SSA uses the information provided on Form SSA-581 to: (1) Identify the wage earner; (2) establish the period of earnings information requested; (3) verify the wage earner authorized SSA to release this information to the requesting party; and (4) produce the Itemized Statement of Earnings (SSA-1826). The respondents are private businesses, state or local agencies, and other federal agencies.
4. Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery—0960-0788. SSA, as part of our continuing effort to reduce paperwork and respondent burden, invites the general public to take this opportunity to comment on the “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery ” for approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501 et. seq.). This collection was developed as part of a Federal Government-wide effort to streamline the process for seeking feedback from the public on service delivery.
Under the auspices of Executive Order 12862, Setting Customer Service Standards, SSA conducts multiple satisfaction surveys each year. This proposed information collection activity provides a means to garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with SSA's commitment to improving service delivery. By qualitative feedback we mean information that provides useful insights on perceptions and opinions, but are not statistical surveys that yield quantitative results that can be generalized to the population of study. This feedback will provide insights into customer or stakeholder perceptions, experiences and expectations, provide an early warning of issues with service, or focus attention on areas where communication, training or changes in operations might improve delivery of products or services. These collections will allow for ongoing, collaborative, and actionable communications between SSA and our customers and stakeholders.
The solicitation of feedback will target areas such as: Timeliness, appropriateness, accuracy of information, courtesy, efficiency of service delivery, and resolution of issues with service delivery. Responses will be assessed to plan and inform efforts to improve or maintain the quality of service offered to the public. If this information is not collected, vital feedback from customers and stakeholders on SSA's services will be unavailable.
We will only submit a collection for approval under this generic clearance if it meets the following conditions: (1) The collections are voluntary; (2) the collections are low-burden for respondents (based on considerations of total burden hours, total number of respondents, or burden-hours per respondent) and are low-cost for both the respondents and the Federal Government; (3) the collections are non-controversial and do not raise issues of concern to other Federal agencies; (4) any collection targeted to the solicitation of opinions from respondents who have experience with the program or may have experience with the program in the near future; (5) personally identifiable information (PII) is collected only to the extent necessary and is not retained; (6) information gathered will be used only internally for general service improvement and program management purposes and is not intended for release outside of the agency; (7) information gathered will not be used for the purpose of substantially informing influential policy decisions; and (8) information gathered will yield qualitative information; the collections will not be designed or expected to yield statistically reliable results or used as though the results are generalizable to the population of study.
Feedback collected under this generic clearance provides useful information, but it does not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior to fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
As a general matter, information collections will not result in any new system of records containing privacy information and will not ask questions of a sensitive nature, such as sexual behavior and attitudes, religious beliefs, and other matters that are commonly considered private.
The respondents are recipients of SSA services (including most members of the public), professionals, and individuals who work on behalf of SSA beneficiaries.
Below we provide projected average estimates for the next three years:
Social Security Administration (SSA).
Notice.
We are giving notice that an agreement coordinating the United States (U.S.) and the Slovak social security programs entered into force on May 1, 2014. The agreement with the Slovak Republic, which was signed on December 10, 2012, is similar to U.S. social security agreements already in force with 24 other countries—Australia, Austria, Belgium, Canada, Chile, the Czech Republic, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Japan, Korea (South), Luxembourg, the Netherlands, Norway, Poland, Portugal, Spain, Sweden, Switzerland and the United Kingdom. Section 233 of the Social Security Act authorizes agreements of this type. 42 U.S.C. 433.
Like the other agreements, the U.S.-Slovak agreement eliminates dual social security coverage. This situation exists when a worker from one country works in the other country and has coverage under the social security systems of both countries for the same work. Without such agreements in force, when
The agreement also helps eliminate situations where workers suffer a loss of benefit rights because they have divided their careers between the two countries. Under the agreement, workers may qualify for partial U.S. benefits or partial Slovak benefits based on combined (totalized) work credits from both countries.
If you want more information about the agreement's provisions, you may write to the Social Security Administration, Office of International Programs, Post Office Box 17741, Baltimore, MD 21235-7741 or visit the Social Security Web site at
Environmental Protection Agency (EPA).
Proposed rule.
In this action, the Environmental Protection Agency (EPA) is proposing emission guidelines for states to follow in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. Specifically, the EPA is proposing state-specific rate-based goals for carbon dioxide emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. This rule, as proposed, would continue progress already underway to reduce carbon dioxide emissions from existing fossil fuel-fired power plants in the United States.
The hearings will provide interested parties the opportunity to present data, views or arguments concerning the proposed action. The EPA will make every effort to accommodate all speakers who arrive and register. Because these hearings are being held at U.S. government facilities, individuals planning to attend the hearing should be prepared to show valid picture identification to the security staff in order to gain access to the meeting room. Please note that the REAL ID Act, passed by Congress in 2005, established new requirements for entering federal facilities. These requirements will take effect July 21, 2014. If your driver's license is issued by Alaska, American Samoa, Arizona, Kentucky, Louisiana, Maine, Massachusetts, Minnesota, Montana, New York, Oklahoma, or the state of Washington, you must present an additional form of identification to enter the federal buildings where the public hearings will be held. Acceptable alternative forms of identification include: Federal employee badges, passports, enhanced driver's licenses and military identification cards. We will list any additional acceptable forms of identification at:
The EPA may ask clarifying questions during the oral presentations, but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral comments and supporting information presented at the public hearing. Commenters should notify Ms. Garrett if they will need specific equipment, or if there are other special needs related to providing comments at the hearings. Verbatim transcripts of the hearings and written statements will be included in the docket for the rulemaking. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule. Additionally, more information regarding the hearings will be available at:
The EPA requests that you also submit a separate copy of your comments to the contact person identified below (see
The
In addition to being available in the docket, an electronic copy of this proposed rule will be available on the Worldwide Web (WWW). Following signature, a copy of this proposed rule will be posted at the following address:
Ms. Amy Vasu, Sector Policies and Programs Division (D205-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-0107, facsimile number (919) 541-4991; email address:
Under the authority of Clean Air Act (CAA) section 111(d), the EPA is proposing emission guidelines for states to follow in developing plans to address greenhouse gas (GHG) emissions from existing fossil fuel-fired electric generating units (EGUs). In this summary, we outline the proposal; discuss its purpose; summarize its major provisions, including the EPA's approach to determining goals; describe the broad range of options available to states, including flexibility in timing requirements both for plan submission and compliance deadlines under those plans; and briefly describe the estimated CO
This rule, as proposed, would continue progress already underway to lower the carbon intensity of power generation in the United States (U.S.). Lower carbon intensity means fewer emissions of CO
Nationwide, by 2030, this rule would achieve CO
Based on evidence from programs already being implemented by many states as well as input received from stakeholders, the agency recognizes that the most cost-effective system of emission reduction for GHG emissions from the power sector under CAA section 111(d) entails not only improving the efficiency of fossil fuel-fired EGUs, but also addressing their utilization by taking advantage of opportunities for lower-emitting generation and reduced electricity demand across the electricity system's interconnecting network or grid.
The proposed guidelines are based on and would reinforce the actions already being taken by states and utilities to upgrade aging electricity infrastructure with 21st century technologies. The guidelines would ensure that these trends continue in ways that are consistent with the long-term planning and investment processes already used in this sector, to meet both region- and state-specific needs. The proposal provides flexibility for states to build upon their progress, and the progress of cities and towns, in addressing GHGs. It also allows states to pursue policies to reduce carbon pollution that: (1)
The proposal has two main elements: (1) State-specific emission rate-based CO
While this proposal lays out state-specific CO
To facilitate the state planning process, this proposal lays out guidelines for the development and implementation of state plans. The proposal describes the components of a state plan, the latitude states have in developing compliance strategies, the flexibility they have in the timing for submittal of their plans and the flexibility they have in determining the schedule by which their sources must achieve the required CO
Addressing a concern raised by both utilities and states, the EPA is proposing that states could choose approaches in their compliance plans under which full responsibility for actions achieving reductions is not placed entirely upon emitting EGUs; instead, state plans could include measures and policies (e.g., demand-side energy efficiency programs and renewable portfolio standards) for which the state itself is responsible. Of course, individual states would also have the option of structuring programs (e.g., allowance-trading programs) under which full responsibility rests on the affected EGUs.
The EPA believes that, using the flexibilities inherent in CAA section 111(d), this proposal would result in significant reductions of GHG emissions that cause harmful climate change, while providing states with ample opportunity to design plans that use innovative, cost-effective strategies that take advantage of investments already being made in programs and measures that lower the carbon intensity of the power sector and reduce GHG emissions.
This proposal is an important step toward achieving the GHG emission reductions needed to address the serious threat of climate change. GHG pollution threatens the American public by leading to potentially rapid, damaging and long-lasting changes in our climate that can have a range of severe negative effects on human health and the environment. CO
The President's Climate Action Plan,
The way that power is produced, distributed and used is already changing due to advancements in innovative power sector technologies and in the availability and cost of low carbon fuel, renewable energy and energy efficient demand-side technologies, as well as economic conditions. In addition, the average age of the coal-fired generating fleet is increasing. In 2025, the average age of the coal-fired generating fleet is
The proposed guidelines are designed to build on and reinforce progress by states, cities and towns, and companies on a growing variety of sustainable strategies to reduce power sector CO
States would be able to rely on and extend programs they may already have created to address the power sector. Those states committed to Integrated Resource Planning (IRP) would be able to establish their CO
States would be able to address the economic interests of their utilities and ratepayers by using the flexibilities in this proposed action to: (1) Reduce costs to consumers, minimize stranded assets, and spur private investments in renewable energy and energy efficiency technologies and businesses; and (2) if they choose, work with other states on multi-state approaches that reflect the regional structure of electricity operating systems that exists in most parts of the country and is critical to ensuring a reliable supply of affordable energy. The proposed rule gives states the flexibility to provide a broad range of compliance options that recognize that the power sector is made up of a diverse range of companies that own and operate fossil fuel-fired EGUs, including vertically integrated companies in regulated markets, independent power producers, rural cooperatives and municipally-owned utilities, all of which are likely to have different ranges of opportunities to reduce GHG emissions while facing different challenges in meeting these reductions.
Both existing state programs (such as RGGI, the California Global Warming Solutions Act program and the Colorado Clean Air, Clean Jobs Act program) and ideas suggested by stakeholders show that there are a number of different ways that states can design programs that achieve required reductions while working within existing market mechanisms used to dispatch power effectively in the short term and to ensure adequate capacity in the long term. These programs and programs for conventional pollutants, such as the Acid Rain Program under Title IV of the CAA, have demonstrated that compliance with environmental programs can be monetized such that it is factored into power sector economic decision making in ways that reduce the cost of controlling pollution, maintain electricity system reliability and work within the least cost dispatching principles that are key to operation of our electric power grid. The proposal would also allow states to work together with individual companies on potential specific challenges. These and other flexibilities are discussed further in Section VIII of the preamble.
Under CAA section 111(d),
To determine the BSER for reducing CO
The proposed guidelines are structured so that states would not be required to use each and every one of the measures that the EPA determines constitute the BSER or to apply any one of those measures to the same extent that the EPA determines is achievable at reasonable cost. Instead, in developing its plan, each state will have the flexibility to select the measure or combination of measures it prefers in order to achieve its CO
As explained in further detail in Sections VI, VII and VIII of this preamble regarding the agency's determination of the BSER, the EPA is offering the opportunity via this proposal to comment on the proposed BSER, the proposed methodology for computing state goals based on application of the BSER, and the state-specific data used in the computations. Once the final goals have been promulgated, a state would no longer have an opportunity to request that the EPA adjust its CO
This proposed rule sets forth the state goals that reflect the BSER and guidelines for states to use in developing their plans to reduce CO
The proposal was substantially informed by the extensive input from states and a wide range of stakeholders that the EPA sought and has received since the summer of 2013. The EPA invites further input through public comment on all aspects of this proposal.
In developing this proposed rulemaking, the EPA is implementing statutory provisions that have been in place since Congress first enacted the CAA in 1970 and that have been implemented pursuant to regulations promulgated in 1975 and followed in subsequent CAA section 111(d) rulemakings. These provisions ensure that, in concert with the provisions of CAA sections 110 and 112, new and existing major stationary sources operate in ways that address their emissions of significant air pollutants that are harmful to public health and the environment. These requirements call on the EPA to develop emission guidelines, which reflect the EPA's determination of the BSER, for states to follow in formulating compliance plans to implement standards of performance to achieve emission reductions consistent with the BSER. In following these provisions, the EPA is proposing a BSER based on strategies currently being used by states and companies to reduce CO
The CAA, as interpreted by the courts, identifies several factors for the EPA to consider in a BSER determination. These include technical feasibility, costs, size of emission reductions and technology (e.g., whether the system promotes the implementation and further development of technology). In determining the BSER, the EPA considered the reductions achievable through measures that reduce CO
As the EPA has done in making BSER determinations in previous CAA section 111(d) rulemakings, the agency considered the types of strategies that states and owners and operators of EGUs are already employing to reduce the covered pollutant (in this case, CO
Such strategies—and the proposed BSER determination—reflect the fact that, in almost all states, the production, distribution and use of electricity can be, and is, undertaken in ways that accommodate reductions in both pollution emission rates and total emissions. Specifically, electricity production, at least to some extent, takes place interchangeably between and among multiple generation facilities and different types of generation, a fact that Congress, the EPA and the states have long relied on in enacting or promulgating pollution reduction programs, such as Title IV of the CAA, the NO
As a result, the agency, in quantifying state goals, assessed what combination of electricity production or energy demand reduction across generation facilities can offer a reasonable-cost, technically feasible approach to achieving CO
Thus, to determine the BSER for reducing CO
1. Reducing the carbon intensity of generation at individual affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs in the amount that results from substituting generation at those EGUs with generation from less carbon-intensive affected EGUs (including NGCC units under construction).
3. Reducing emissions from affected EGUs in the amount that results from substituting generation at those EGUs with expanded low- or zero-carbon generation.
4. Reducing emissions from affected EGUs in the amount that results from the use of demand-side energy efficiency that reduces the amount of generation required.
The four building blocks are described in detail in Sections VI of this preamble. As explained in that section, the EPA evaluated each of the building blocks individually against the BSER criteria and found that each of the building blocks independently merits consideration as part of the BSER. The EPA also evaluated combinations of the building blocks against the BSER criteria—in particular, a combination of all four building blocks and a combination of building blocks 1 and 2.
Based on that evaluation, the EPA proposes that the combination of all four building blocks is the BSER. The combination of all four blocks best represents the BSER because it achieves greater emission reductions at a lower cost, takes better advantage of the wide range of measures that states, cities, towns and utilities are already using to reduce CO
As part of the BSER determination, the EPA considered the impacts that implementation of the emission reductions based on the combination of the blocks would have on the cost of electricity and electricity system reliability. As the preamble details, the EPA believes that, both with respect to the overall proposed BSER and with respect to the individual building blocks, the associated costs are reasonable. Importantly, the proposed BSER, expressed as a numeric goal for each state, provides states with the flexibility to determine how to achieve the reductions (i.e., greater reductions from one building block and less from another) and to adjust the timing in which reductions are achieved, in order to address key issues such as cost to consumers, electricity system reliability and the remaining useful life of existing generation assets.
In sum, the EPA proposes that the BSER for purposes of CAA section 111(d), as applied to existing fossil fuel-fired EGUs, is based on a combination of measures that reduce CO
In determining the BSER, we have considered the ranges of reductions that can be achieved by application of each building block, and we have identified goals that we believe reflect a reasonable degree of application of each building block consistent with the BSER criteria. Relying on all four building blocks to characterize the combination of measures that reduce CO
The EPA recognizes that states differ in important ways, including in their mix of existing EGUs and in their policy priorities. Consequently, opportunities and preferences for reducing emissions, as reflected in each of the building blocks, vary across states. While the state-specific goals that the EPA is proposing in this rule are based on consistent application of a single goal-setting methodology across all states, the goals account for these key differences. The state-specific CO
The proposed BSER and goal-setting methodology reflect information provided and priorities expressed during the EPA's recent, extensive public outreach process. The input we received ranged from the states' desires for flexibility and recognition of varying state circumstances to the success that states and companies have had in adopting a range of pollution—and demand-reduction strategies. The state-specific approach embodied in both CAA section 111(d) and this proposal recognizes that ultimately states are the most knowledgeable about their specific circumstances and are best positioned to evaluate and leverage existing and new generation capacity and programs to reduce CO
To meet its goal, each state will be able to design programs that use the measures it selects, and these may include the combination of building blocks most relevant to its specific circumstances and policy preferences. States may also identify technologies or strategies that are not explicitly mentioned in any of the four building blocks and may use those technologies or strategies as part of their overall plans (e.g., market-based trading programs or construction of new natural combined cycle units or nuclear plants). Further, the EPA's approach allows multi-state compliance strategies.
The agency also recognizes the important functional relationship between the period of time over which measures are deployed and the stringency of emission limitations those measures can achieve in a practical and reasonable cost way. Because, for this proposal, the EPA is proposing a 10-year period over which to achieve the full required CO
In this action, the EPA is proposing state-specific rate-based goals that state plans must be designed to meet. These state-specific goals are based on an assessment of the amount of emissions that can be reduced at existing fossil fuel-fired EGUs through application of the BSER, as required under CAA section 111(d). The agency is proposing state-specific final goals that must be achieved by no later than the year 2030. The proposed final goals reflect the EPA's quantification of adjusted state-average emission rates from affected EGUs that could be achieved at reasonable cost by 2030 through implementation of the four building blocks described above.
The EPA recognizes that, with many measures, states can achieve emission reductions in the short-term, though the full effects of implementation of other measures, such as demand-side energy efficiency (EE) programs and the addition of renewable energy (RE) generating capacity, can take longer. Thus, the EPA is proposing interim goals that states must meet beginning in 2020. The proposed interim goals would apply over a 2020-2029 phase-in period. They reflect the level of reductions in CO
The EPA is proposing to allow each state flexibility with regard to the form of the goal. A state could adopt the rate-based form of the goal established by the EPA or an equivalent mass-based form of the goal. A multi-state approach incorporating either a rate- or mass-based goal would also be approvable based upon a demonstration that the state's plan would achieve the equivalent in stringency, including compliance timing, to the state-specific rate-based goal set by the EPA.
We believe that this approach to establishing requirements for states in developing their plans responds both to the needs of an effectively implemented program and to the range of viewpoints expressed by stakeholders regarding the simultaneous need for both flexibility and clear guidance on what would constitute an approvable state plan. We likewise believe that this approach represents a reasonable balance between two competing objectives grounded in CAA section 111(d)—a need for rigor and consistency in calculating emission reductions reflecting the BSER and a need to provide the states with flexibility in establishing and implementing the standards of performance that reflect those emission reductions. The importance of this balance is heightened by the fact that the operations of the electricity system itself rely on the flexibility made available and achieved through dispatching between and among multiple interconnected EGUs, demand management and end-use energy efficiency. We view the proposed goals as providing rigor where required by the statute with respect to the amount of emission reductions, while providing states with flexibility where permitted by the statute, particularly with respect to the range of measures that a state could include in its plan. This approach recognizes that state plans for emission reductions can, and must, be consistent with a vibrant and growing economy and supply of reliable, affordable electricity to support that economy. It further reflects the growing trend, as exemplified by many state and local clean energy policies and programs, to shift energy production away from carbon-intensive fuels to a modern, more sustainable system that puts greater reliance on renewable energy, energy efficiency and other low-carbon energy options.
Each state will determine, and include in its plan, emission performance levels for its affected EGUs that are equivalent to the state-specific CO
A state plan must include enforceable CO
In this action, the EPA is also proposing guidelines for states to follow in developing their plans. These guidelines include approvability criteria, requirements for state plan components, the process and timing for state plan submittal and the process and timing for demonstrating achievement of the CO
With respect to the structure of the state plans, the EPA, in its extensive outreach efforts, heard from a wide range of stakeholders that the EPA should authorize state plans to include a portfolio of actions that encompass a diverse set of programs and measures that achieve either a rate-based or mass-based emission performance level for affected EGUs but that do not place legal responsibility for achieving the entire amount of the emission performance level on the affected EGUs. In view of this strong sentiment from stakeholders, the EPA is proposing that state plans that take this portfolio approach would be approvable, provided that they meet other key requirements such as achieving the required emission reductions over the appropriate timeframes. Plans that do directly assure that affected EGUs achieve all of the required emission reductions (such as the mass-based programs being implemented in California and the RGGI states) would also be approvable provided that they meet other key requirements, such as achieving the required emission reductions over the appropriate timeframes.
The EPA is proposing to evaluate and approve state plans based on four general criteria: (1) Enforceable measures that reduce EGU CO
Recognizing the urgent need for actions to reduce GHG emissions, and in accordance with the Presidential Memorandum,
If the initial plan includes those components and if the EPA does not notify the state that the initial plan does not contain the required components, the extension of time to submit a complete plan will be deemed granted and a state would have until June 30, 2017, to submit a complete plan if the geographic scope of the plan is limited to that state. If the state develops a plan that includes a multi-state approach, it would have until June 30, 2018 to submit a complete plan. Further, the EPA is proposing that states participating in a multi-state plan may submit a single joint plan on behalf of all of the participating states.
Following submission of final plans, the EPA will review plan submittals for approvability. Given the diverse approaches states may take to meet the emission performance goals in the emission guidelines, the EPA is proposing to extend the period for EPA review and approval or disapproval of plans from the four-month period provided in the EPA framework regulations to a twelve-month period.
As states, industry groups and other stakeholders have made clear, the EPA recognizes that the measures states have been and will be taking to reduce CO
The EPA is also proposing that measures that a state takes after the date of this proposal, or programs already in place, which result in CO
To respond to requests from states for methodologies, tools and information to assist them in designing and implementing their plans, the EPA, in consultation with the U.S. Department of Energy and other federal agencies, as well as states, is collecting and developing available resources and is making those resources available to the states via a dedicated Web site.
Under the proposed guidelines, the EPA projects annual CO
Actions taken to comply with the proposed guidelines will reduce emissions of CO
Assuming that states comply with the guidelines collaboratively (referred to as the regional compliance approach), the EPA estimates that, in 2020, this proposal will yield monetized climate benefits of approximately $17 billion (2011$) using a 3 percent discount rate (model average) relative to the 2020 base case, as shown in Table 1.
In comparison, if states choose to comply with the guidelines on a state-specific basis (referred to as state compliance approach), the climate benefits in 2020 are expected to be approximately $18 billion (3 percent discount rate, model average, 2011$), as Table 1 shows. Health co-benefits are estimated to be $17 to $40 billion (3 percent discount rate) and $15 to $36 billion (7 percent discount rate). Total compliance costs are approximately $7.5 billion annually in 2020. Net benefits in 2020 are estimated to be $27 to $50 billion (3 percent model average discount rate, 2011$). In 2030, as shown on Table 2, climate benefits are approximately $31 billion using a 3 percent discount rate (model average, 2011$) relative to the 2030 base case assuming a state compliance approach. Health co-benefits are estimated to be approximately $27 to $62 billion (3 percent discount rate) and $24 to $56 billion (7 percent discount rate) relative to the 2030 base case (2011$). In 2030, total compliance costs for the state approach are approximately $8.8 billion (2011$). In 2030, these net benefits are estimated to be approximately $49 to $84 billion (3 percent discount rate, 2011$) assuming a state compliance approach.
There are additional important benefits that the EPA could not monetize. These unquantified benefits include climate benefits from reducing emissions of non-CO
In addition to the cost and benefits of the rule, the EPA projects the employment impacts of the guidelines. We project job gains and losses relative to base case for the electric generation, coal and natural gas production, and demand side energy efficiency sectors. In 2020, we project job growth of 25,900 to 28,000 job-years
Based upon the foregoing, it is clear that the monetized benefits of this proposal are substantial and far outweigh the costs.
This action presents the EPA's proposed emission guidelines for states to consider in developing plans to reduce GHG emissions from the electric power sector. Section II provides background on climate change impacts from GHG emissions, GHG emissions from fossil fuel-fired EGUs and the utility power sector and CAA section 111(d) requirements. Section III presents a summary of the EPA's stakeholder outreach efforts, key messages provided by stakeholders, state policies and programs that reduce GHG emissions, and conclusions. In Section IV of the preamble, we present a summary of the rule requirements and the legal basis for these. Section V explains the EPA authority to regulate CO
We note that this rulemaking overlaps in certain respects with two other related rulemakings: The January 2014 proposed rulemaking that the EPA published on January 8, 2014 for CO
In this section, we discuss climate change impacts from GHG emissions, both on public health and public welfare, present information about GHG emissions from fossil fuel fired EGUs, and summarize the statutory and regulatory requirements relevant to this rulemaking.
In 2009, the EPA Administrator issued the document known as the Endangerment Finding under CAA section 202(a)(1).
Climate change caused by human emissions of GHGs threatens public health in multiple ways. By raising average temperatures, climate change
Climate change caused by human emissions of GHGs also threatens public welfare in multiple ways. Climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face increased risks from storm and flooding damage to property, as well as adverse impacts from rising sea level, such as land loss due to inundation, erosion, wetland submergence and habitat loss. Climate change is expected to result in an increase in peak electricity demand, and extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities. Climate change also is very likely to fundamentally rearrange U.S. ecosystems over the 21st century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S.
As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA's approach to providing the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. Since the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, a number of such assessments have been released. These assessments include the IPCC's 2012 “Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” (SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP's 2014 “Climate Change Impacts in the United States” (Climate Change Impacts), and the NRC's 2010 “Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean” (Ocean Acidification), 2011 “Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia” (Climate Stabilization Targets), 2011 “National Security Implications for U.S. Naval Forces” (National Security Implications), 2011 “Understanding Earth's Deep Past: Lessons for Our Climate Future” (Understanding Earth's Deep Past), 2012 “Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future”, 2012 “Climate and Social Stress: Implications for Security Analysis” (Climate and Social Stress), and 2013 “Abrupt Impacts of Climate Change” (Abrupt Impacts) assessments.
The EPA has reviewed these new assessments and finds that the improved understanding of the climate system they present strengthens the case that GHGs endanger public health and welfare.
In addition, these assessments highlight the urgency of the situation as the concentration of CO
What this means, as stated in another NRC assessment, is that:
Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth's climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe. Therefore, emission reductions choices made today matter in determining impacts experienced not just over the next few decades, but in the coming centuries and millennia.
Moreover, due to the time-lags inherent in the Earth's climate, the Climate Stabilization Targets assessment notes that the full warming from any given concentration of CO
The recently released USGCRP “Climate Change Impacts” assessment
These assessments underscore the urgency of reducing emissions now: Today's emissions will otherwise lead to raised atmospheric concentrations for thousands of years, and raised Earth system temperatures for even longer. Emission reductions today will benefit the public health and public welfare of current and future generations.
Finally, it should be noted that the concentration of carbon dioxide in the atmosphere continues to rise dramatically. In 2009, the year of the Endangerment Finding, the average concentration of carbon dioxide as
Fossil fuel-fired electric utility generating units (EGUs) are by far the largest emitters of GHGs, primarily in the form of CO
The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks
Total fossil energy-related CO
Electricity in the United States is generated by a range of sources—from power plants that use fossil fuels like coal, oil, and natural gas, to non-fossil sources, such as nuclear, solar, wind and hydroelectric power. In 2013, over 67 percent of power in the U.S. was generated from the combustion of coal, natural gas, and other fossil fuels, over 40 percent from coal and over 26 percent from natural gas.
This range of different power plants generates electricity that is transmitted and distributed through a complex system of interconnected components to industrial, business, and residential consumers.
The utility power sector is unique in that, unlike other sectors where the sources operate independently and on a local scale, power sources operate in a complex, interconnected grid system that typically is regional in scale. In addition, the U.S. economy depends on this sector for a reliable supply of power at a reasonable cost.
In the U.S., much of the existing power generation fleet in the infrastructure is aging. There has been, and continues to be, technological advancement in many areas, including energy efficiency, solar power generation, and wind power generation. Advancements and innovation in power sector technologies provide the opportunity to address CO
Clean Air Act section 111, which Congress enacted as part of the 1970 Clean Air Act Amendments, establishes mechanisms for controlling emissions of air pollutants from stationary sources. This provision requires the EPA to promulgate a list of categories of stationary sources that the Administrator, in his or her judgment, finds “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”
When the EPA establishes NSPS for new sources in a particular source category, the EPA is also required, under CAA section 111(d)(1), to prescribe regulations for states to submit plans regulating existing sources in that source category for any air pollutant that, in general, is not regulated under the CAA section 109 requirements for the NAAQS or regulated under the CAA section 112 requirements for hazardous air pollutants (HAP). CAA section 111(d)'s mechanism for regulating existing sources differs from the one that CAA section 111(b) provides for new sources because CAA section 111(d) contemplates states submitting plans that establish “standards of performance” for the affected sources and that contain other measures to implement and enforce those standards.
“Standards of performance” are defined under CAA section 111(a)(1) as standards for emissions that reflect the emission limitation achievable from the “best system of emission reduction,” considering costs and other factors, that “the Administrator determines has been adequately demonstrated.” CAA section 111(d)(1) grants states the authority, in applying a standard of performance to particular sources, to take into account the source's remaining useful life or other factors.
Under CAA section 111(d), a state must submit its plan to the EPA for approval, and the EPA must approve the state plan if it is “satisfactory.”
The EPA issued regulations implementing CAA section 111(d) in 1975,
Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (i.e., sulfuric acid plants (acid mist), phosphate fertilizer plants (fluorides), primary aluminum plants (fluorides), Kraft pulp plants (total reduced sulfur), and municipal solid waste landfills (landfill gases)).
The EPA's previous CAA section 111(d) actions were necessarily geared toward the pollutants and industries regulated. Similarly, in this proposed rulemaking, in defining CAA section 111(d) emission guidelines for the states and determining the BSER, the EPA believes that taking into account the particular characteristics of carbon pollution, the interconnected nature of the power sector and the manner in which EGUs are currently operated is warranted. Specifically, the operators themselves treat increments of generation as interchangeable between and among sources in a way that creates options for relying on varying utilization levels, lowering carbon generation, and reducing demand as components of the overall method for reducing CO
In this action, the EPA is proposing emission guidelines for states to follow in developing their plans to reduce emissions of CO
Following the direction of the Presidential Memorandum to the Administrator (June 25, 2013),
Launch this effort through direct engagement with States, as they will play a central role in establishing and implementing standards for existing power plants, and, at the same time, with leaders in the power sector, labor leaders, non-governmental organizations, other experts, tribal officials, other stakeholders, and members of the public, on issues informing the design of the program.
To carry out this stakeholder outreach, the EPA embarked on an unprecedented pre-proposal outreach effort. From consumer groups to states to power plant owner/operators to technology innovators, the EPA sought input from all perspectives.
The EPA began the outreach efforts with a webinar and associated teleconferences to establish a common understanding of the basic requirements and process of CAA section 111(d). The August 27, 2013 overview presentation was offered as a webinar for state and tribal officials, “Building a Common Understanding: Clean Air Act and Upcoming Carbon Pollution Guidelines for Existing Power Plants.”
The EPA followed up on the presentation by offering four national teleconference calls with representatives from states, tribes, industry, environmental justice organizations, community organizations and environmental representatives. The teleconferences offered a venue for stakeholders to ask questions of the EPA about the overview presentation and for the EPA to gather initial reactions from stakeholders. Stakeholders and members of the public continued to view and refer to the overview presentation throughout the outreach process. By May 2014, the presentation had been viewed more than 5,600 times.
The agency also provided mechanisms for anyone from the public to provide input during the pre-proposal development of this action. The EPA set up two user-friendly options to accept input during the pre-proposal period—email and a web-based form. The EPA has received more than 2,000 emails offering input into the development of these guidelines.
These emails and other materials provided to the EPA are posted on line as part of a non-regulatory docket, EPA Docket ID No. EPA-HQ-OAR-2014-0020, at
The agency has encouraged, organized, and participated in hundreds of meetings about CAA section 111(d) and reducing carbon pollution from existing power plants. Attendees at these various meetings have included states and tribes, members of the public, and representatives from multiple industries, labor leaders, environmental groups and other non-governmental organizations. The direct engagement has brought together a variety of states and stakeholders to discuss a wide range of issues related to the electricity sector and the development of emission guidelines under CAA section 111(d). The meetings occurred in Washington, DC, and at locations across the country. The meetings were attended by the EPA Regional Administrators, managers and staff and who are playing or will play key roles in developing and implementing the rule.
Part of this effort included the agency's holding of 11 public listening sessions; one national listening session in Washington, DC and 10 listening sessions in locations in the EPA regional offices across the country. All of the outreach meetings were designed to solicit policy ideas, concerns and technical information from stakeholders about using CAA section 111(d).
This outreach process has produced a wealth of information which has informed this proposal significantly. The pre-proposal outreach efforts far exceeded what is required of the agency in the normal course of a rulemaking process, and the EPA expects that the dialog with states and stakeholders will continue throughout the process and even after the rule is finalized. The EPA recognizes the importance of working with all stakeholders, and in particular with the states, to ensure a clear and common understanding of the role the
More than 3,300 people attended the public listening sessions held in 11 cities across the country. Holding the listening sessions at the EPA's regional offices offered thousands of people from different parts of the country the opportunity to provide input to EPA officials in accessible venues. In addition to being well located, holding the sessions in regional offices also allowed the agency to use resources prudently and enabled a variety of the EPA staff involved in the development and ultimate implementation of this upcoming rule to attend and learn from the views expressed.
More than 1,600 people spoke at the 11 listening sessions. Speakers included Members of Congress, other public officials, industry representatives, faith-based organizations, unions, environmental groups, community groups, students, public health groups, energy groups, academia and concerned citizens. Participants shared a range of perspectives. Many were concerned by the impacts of climate change on their health and on future generations, others worried about the impact of regulations on the economy. Their support for the agency's efforts varied.
Summaries of these 11 public listening sessions are available at
Since fall 2013, the agency provided multiple opportunities for the states to inform this proposal. In addition, the EPA organized, encouraged and attended meetings to discuss multi-state planning efforts. Because of the interconnectedness of the power sector, and the fact that electricity generated at power plants crosses state lines, states, utilities and ratepayers may benefit from states working together to address the requirements of this rulemaking implementation. The meetings provided state leaders, including governors, environmental commissioners, energy officers, public utility commissioners, and air directors, opportunities to engage with the EPA officials.
Agency officials listened to ideas, concerns and details from states, including from states with a wide range of experience in reducing carbon pollution from power plants. The agency has collected policy papers from states with overarching energy goals and technical details on the states' electricity sector. The agency has engaged, and will continue to engage with, all of the 50 states throughout the rulemaking process.
The EPA conducted significant outreach to tribes, who are not required to—but may—develop or adopt Clean Air Act programs. The EPA is aware of three coal-fired power plants and one natural gas-fired EGU located in Indian country but is not aware of any EGUs that are owned or operated by tribal entities.
The EPA conducted outreach to tribal environmental staff and offered consultation with tribal officials in developing this action. Because the EPA is aware of tribal interest in this proposed rule, the EPA offered consultation with tribal officials early in the process of developing the proposed regulation to permit tribes to have meaningful and timely input into its development.
The EPA sent consultation letters to 584 tribal leaders. The letters provided information regarding the EPA's development of emission guidelines for existing power plants and offered consultation. None have requested consultation. Tribes were invited to participate in the national informational webinar held August 27, 2013. In addition, a consultation/outreach meeting was held on September 9, 2013, with tribal representatives from some of the 584 tribes. The EPA representatives also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on December 19, 2013. In those teleconferences, the EPA provided background information on the GHG emission guidelines to be developed and a summary of issues being explored by the agency.
In addition, the EPA held a series of listening sessions prior to development of this proposed action. Tribes participated in a session on September 9, 2013 with the state agencies, as well as in a separate session with tribes on September 26, 2013.
Agency officials have engaged with industry leaders and representatives from trade associations in scores of one-on-one and national meetings. Many meetings occurred at the EPA headquarters and in the EPA's Regional Offices and some were sponsored by stakeholder groups. Because the focus of the standard is on the electricity sector, many of the meetings with industry have been with utilities and industry representatives directly related to the electricity sector. The agency has also met with energy industries such as coal and natural gas interests, as well as companies that offer new technology to prevent or reduce carbon pollution, including companies that have expertise in renewable energy and energy efficiency. Other meetings have been held with representatives of energy intensive industries, such as the iron and steel and aluminum industries to help understand the issues related to large industrial users of electricity.
Agency officials participated in many meetings with utilities and their associations. The meetings focused on the importance of the utility industry in reducing carbon emissions from power plants. Power plant emissions are central to this rulemaking. The EPA encouraged industry representatives to work with state environmental and energy officers.
The electric utility representatives included private utilities or investor owned utilities. Public utilities and cooperative utilities were also part of in-depth conversations about CAA section 111(d) with EPA officials.
The conversations included meetings with the EPA headquarters and Regional offices. State officials were included in many of the meetings. Meetings with utility associations and groups of utilities were held with key EPA officials. The meetings covered technical, policy, and legal topics of interest and utilities expressed a wide variety of support and concerns about CAA section 111(d).
The EPA had a number of conversations with the Independent System Operators and Regional Transmission Organizations (ISOs and RTOs) to discuss the rule and issues related to grid operations and reliability. EPA staff met with the ISO/RTO Council on several occasions to collect their ideas. The EPA Regional Offices also met with the ISOs and RTOs in their regions. System operators have offered suggestions in using regional approaches to implement CAA section 111(d) while maintaining reliable, affordable electricity.
Agency officials engaged with representatives of environmental justice organizations during the outreach effort, for example, we engaged with the National Environmental Justice Advisory Council members in September 2013. The NEJAC is composed of stakeholders, including environmental justice leaders and other
The EPA has also met with a number of environmental groups to provide their ideas on how to reduce carbon pollution from existing power plants using section 111(d) of the CAA.
Many environmental organizations discussed the need for reducing carbon pollution. Meetings were technical, policy and legal in nature and many groups discussed specific state policies that are already in place to reduce carbon pollution in the states.
A number of organizations representing religious groups have reached out to the EPA on several occasions to discuss their concerns and ideas regarding this rule.
Public health groups discussed the need for protection of children's health from harmful air pollution. Doctors and health care providers discussed the link between reducing carbon pollution and air pollution and public health. Consumer groups representing advocates for low income electricity customers discussed the need for affordable electricity. They talked about reducing electricity prices for consumers through energy efficiency and low cost carbon reductions.
EPA senior officials and staff met with a number of labor union representatives about reducing carbon pollution using CAA section 111(d). Those unions included: The United Mine Workers of America; the Sheet Metal, Air, Rail and Transportation Union (SMART); the International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (IBB); United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of the United States and Canada; the International Brotherhood of Electrical Workers (IBEW): And the Utility Workers Union of America. In addition, agency leaders met with the Presidents of several unions and the President of the American Federation of Labor-Congress of Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters.
EPA officials, when invited, attended meetings sponsored by labor unions to give presentations and engage in discussions about reducing carbon pollution using CAA section 111(d). These included meetings sponsored by the IBB and the IBEW.
Many stakeholders stated that opportunities exist to reduce the carbon emissions from existing power generation through a wide range of measures, from measures that are implementable via physical changes at the source to those that also are implementable across the broader power generation system. Opinions varied about how broader system measures could factor into programs to reduce carbon pollution. Some stakeholders recommended that system-wide measures be allowed for compliance, but not factored into the carbon improvement goals the EPA establishes, while others recommended that system-wide measures be factored into the goals. Among the arguments and information offered by stakeholders who suggested that states be encouraged to incorporate system-wide measures into their state plans and that EGU operators be encouraged to rely on such measures were examples and discussions of the significant extent to which dispatch, end use energy efficiency and renewable energy had already proven to be successful strategies for reducing EGU CO
Views on the form and stringency of the goal or guidelines varied. Some stakeholders preferred a rate-based form of the goal, while others preferred a mass-based form. In addition, some stakeholders recommended that the EPA let the states have the flexibility to either choose among multiple forms of the goals or to set their own goals. With regard to the stringency of the goal, some stakeholders recommended that the stringency of the goals vary by state, to account for differences in state circumstances.
Many stakeholders recognized the value of allowing states flexibility in implementing the goals the EPA establishes. For example, states highlighted the importance of the EPA recognizing existing state and regional programs that address carbon pollution, including market-based programs, and allowing credit for prior accomplishments in reducing CO
Many stakeholders recommended that states be allowed to develop multi-state programs. It was frequently noted that such regional approaches could offer cost-effective carbon pollution solutions.
There was broad agreement that most states would need more than one year to develop and submit their complete plans to the EPA. For some states, more time is necessary because of the state legislative schedule and/or regulatory process. In some cases, approval of a plan through a state's legislative or regulatory process could take one year or more after the plan has already been developed. Additional time would also allow and encourage multi-state and regional partnerships and programs.
Many stakeholders also supported flexibility in the timing of implementation of the state plans and power sector compliance with the goals in the state plans. Such flexibility, some stakeholders asserted, would accommodate the diverse GHG mitigation potential of states and support more cost-effective approaches to achieving CO
During the outreach process, some stakeholders raised general concerns that the rulemaking could have a negative impact on jobs and ratepayers. Some stakeholders also expressed concerns about potential adverse effects on electric system reliability. Some stakeholders were concerned that meeting the goals could potentially result in stranded generation assets. To prevent this from occurring, some stakeholders suggested varying the stringency of standards to account for individual state circumstances and variation.
The EPA has given stakeholder input careful consideration during the development of this proposal and, as a result, this proposal includes features that are intended to be responsive to many stakeholder concerns.
During the EPA's public outreach in advance of this proposal, a number of ideas were put forward that are not fully reflected in this proposal. We invite public comment on these ideas, some of which are outlined below.
Some groups thought that the EPA should put forward a model rule for an interstate emissions credit trading program that could be easily adopted by states who wanted to use such a
One group recommended that state programs be allowed to demonstrate equivalency using one of three tests: Rate-based equivalency via a demonstration that the state program achieves equivalent or better carbon intensity for the regulated sector; mass-based equivalency via a demonstration that the program achieves equal or greater emission reductions relative to what would be achieved by the federal approach; or a market price-based equivalency via a demonstration that the program reflects a carbon price comparable to or greater than the cost-effectiveness benchmark used by the EPA in designing the program. The EPA is proposing a way to demonstrate equivalency and that is discussed in Section VIII of this preamble.
Other stakeholders suggested that an “inside the fence” plant- or unit-specific assessment linked to the availability of control at the source such as heat rate improvements should be considered. They indicated that once plant-specific goals are established based on on-site CO
The EPA invites comment on these suggestions.
Across the nation, many states and regions have shown strong leadership in creating and implementing policies and programs that reduce GHG emissions from the power sector while achieving other economic, environmental, and energy benefits. Some of these activities, such as market-based programs and GHG performance standards, directly require GHG emission reductions from EGUs. Others reduce GHG emissions by reducing utilization of fossil fuel-fired EGUs through, for example, renewable portfolio standards (RPS) and energy efficiency resource standards (EERS), which alter the mix of energy supply and reduce energy demand. States have developed their policies and programs with stakeholder input and tailored them to their own circumstances and priorities. Their leadership and experiences provided the EPA with important information about best practices to build upon in this proposed rule. As directed by the Presidential Memorandum, the EPA is, with this proposal to reduce power plant carbon pollution, building on actions already underway in states and the power sector.
Nine states actively participate in the Regional Greenhouse Gas Initiative (RGGI), a market-based CO
Approximately 90 percent of CO
Between 2005, when an agreement to implement RGGI was announced, and 2012, power sector CO
Similarly, California established an economy-wide market-based GHG emissions trading program under the authority of its 2006 Global Warming Solutions Act, which requires the state to reduce its 2020 GHG emissions to 1990 levels.
Four states, California, New York, Oregon and Washington, have enacted GHG emission standards that impose enforceable emission limits on new and/or expanded electric generating units. For example, since 2012, New York requires new or expanded baseload plants that are greater than 25 Megawatts (MW) to meet an emission rate of either 925 pounds CO
Three states, California, Oregon and Washington, have enacted GHG emission performance standards that set an emission rate for electricity purchased by electric utilities. In both Oregon and Washington, for example, electric utilities may enter into long term power purchase agreements for baseload power only if the electric generator supplying the power has a CO
Two states, Minnesota and Colorado, have worked collaboratively with their investor-owned utilities to develop multi-pollutant emission reduction plans on a utility-wide basis. This multi-pollutant, collaborative approach enables utilities to determine the least cost way to meet long term and comprehensive energy and environmental goals.
Colorado's Clean Air, Clean Jobs Act of 2010, for example, required Colorado investor-owned utilities with coal plants to develop a multi-pollutant plan to meet existing and reasonably foreseeable federal CAA requirements.
More than 25 states have mandatory renewable portfolio standards that require retail electricity suppliers to supply a minimum percentage or amount of their retail electricity load with electricity generated from eligible sources of renewable energy.
In 2007, the Minnesota legislature amended the state's 2001 renewable energy objective and established a renewable energy standard (RES) requiring at least 25 percent of all electricity generated or purchased in Minnesota to come from renewable energy by 2025. The standard sets requirements and timetables, beginning in 2010, that vary based on the provider. For example, in 2011, Xcel Energy had a requirement to generate or purchase 15 percent of its total retail sales from renewable energy while all other utilities had a target of 7 percent of total retail sales. According to the latest Minnesota Department of Commerce report to the legislature on progress, all utilities subject to the standard met it for 2011 and were on track to meet their 2012 goals.
The Oregon Renewable Portfolio Standard (RPS) is another example of a state requirement for renewables. Originally enacted in 2007, it requires that all utilities serving Oregon meet a percentage of their retail electricity needs with qualified renewable resources. Like in Minnesota, the percentage varies across utilities with the three largest utilities required to reach five percent from renewable energy sources starting in 2011, 15 percent in 2015, 20 percent in 2020, and 25 percent in 2025. Other electric utilities in the state are required to reach levels of five percent or ten percent by 2025, depending on their size. According to the latest RPS compliance reports submitted by the largest utilities for the state, each had achieved the five percent target as of the end of 2012.
Many electric utilities, third-party administrators, and states implement demand-side energy efficiency programs to reduce generation from EGUs by reducing electricity use, including peak demand. When these programs reduce fossil fuel electricity generation, they also reduce CO
The purposes of demand-side energy efficiency programs vary; goals include to reduce GHG emissions by reducing fossil-fired generation, help states achieve energy savings goals, save energy and money for consumers and improve electricity reliability. They are typically funded through a small fee or surcharge on customer electricity bills, but can also be funded by other sources, such as from RGGI CO
Nationally, total spending on electric ratepayer-funded energy efficiency programs was about $5 billion in 2012.
Electricity savings from energy efficiency programs are also growing. In 2011, electricity savings from these programs totaled approximately 22.9 million MWh, a 22 percent increase from the previous year.
California has been advancing energy efficiency through utility-run demand-side energy efficiency programs for decades and considers energy efficiency “the bedrock upon which climate policies are built.”
In Vermont, for example, the Vermont Legislature and the Vermont Public Service Board (PSB) established the first statewide “energy efficiency utility” in 1999 to provide energy efficiency services to residences and businesses throughout the state.
More than 20 states have energy efficiency resource standards (EERS) that require utilities to save a certain amount of energy each year or cumulatively.
In Arizona, for example, the Arizona Corporation Commission (ACC) adopted rules in 2010 requiring all investor-owned utilities to achieve 22 percent cumulative electricity savings by 2020, making it one of the highest standards in the nation.
States have taken a leadership role in mitigating GHG emissions and have demonstrated the potential for national application of a number of approaches. Throughout the development of this proposed rule, the EPA considered the states' experiences and lessons learned regarding the design and implementation of successful GHG mitigation programs. The agency also fully considered input from stakeholders during the development of this proposed rulemaking.
Considering all input from stakeholders, the agency recognizes that the most cost-effective approach to reducing GHG emissions from the power sector under CAA section 111(d) is to follow the lead of numerous states and not only to identify improvements in the efficiency of fossil fuel-fired EGUs as a component of the BSER, but also include in the BSER determination the EGU-emissions-reduction opportunities that states have already demonstrated to be successful in relying on lower- and zero-emitting generation and reduced electricity demand.
CAA section 111(d) sets up a partnership between the EPA and the states. In the context of that partnership, the EPA recognizes the importance of each state having the flexibility to design a cost-effective program tailored to its own specific circumstances. The agency also recognizes, as many states
The EPA is proposing emission guidelines for each state to use in developing plans to address greenhouse gas emissions from existing fossil fuel-fired electric generating units. The emission guidelines are based on the EPA's determination of the “best system of emission reduction . . . adequately demonstrated” (BSER) and include state-specific goals, general approvability criteria for state plans, requirements for state plan components, and requirements for the process and timing for state plan submittal and compliance.
Under CAA section 111(d), the states must establish standards of performance that reflect the degree of emission limitation achievable through the application of the “best system of emission reduction” that, taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements, the Administrator determines has been adequately demonstrated. Consistent with CAA section 111(d), the EPA is proposing state-specific goals that reflect the EPA's calculation of the BSER.
Under CAA section 111(d), each state must develop, adopt, and then submit its plan to the EPA. To do so, the state would determine, and include in its plan, an emission performance level that is equivalent to the state-specific CO
The EPA is proposing to determine the BSER as the combination of emission rate improvements and limitations on overall emissions at affected EGUs that can be accomplished through any combination of one or more measures from the following four sets of measures or building blocks:
1. Reducing the carbon intensity of generation at individual affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs in the amount that results from substituting generation at those EGUs with generation from less carbon-intensive affected EGUs (including natural gas combined cycle (NGCC) units that are under construction).
3. Reducing emissions from affected EGUs in the amount that results from substituting generation at those EGUs with expanded low- or zero-carbon generation.
4. Reducing emissions from affected EGUs in the amount that results from the use of demand-side energy efficiency that reduces the amount of generation required.
The EPA has reviewed information about the current and recent performance of affected EGUs and states' implementation of programs that reduce CO
Based on the EPA's application of the BSER to each state, the EPA is proposing to establish, as part of the emission guidelines, state-specific goals, expressed as average emission rates for fossil fuel-fired EGUs. Each state's goals comprise the EPA's determination of the emission limitation achievable through application of the BSER in that state. For each state, the EPA is proposing an interim goal for the phase-in period from 2020 to 2029 and the final goal that applies beginning in 2030. The proposed goals for each state are listed in Section VII, below. The EPA is proposing that measures that a state takes after the date of this proposal, and that result in CO
The EPA is further proposing, as part of the plan guidelines, timetables for states to submit their plans. The agency expects to finalize this rulemaking by June 2015, and we are proposing to require that each state submit its plan to the EPA by June 30, 2016. However, if a state needs additional time to submit a complete plan, the state must submit an initial plan by June 30, 2016, that documents the reasons why more time is needed to submit a complete plan and includes commitments to take concrete steps that will ensure that the state will submit a complete plan by June 30, 2017, or June 30, 2018, as appropriate. If such a state is developing a plan limited in geographical scope to the individual state, then the state would have until June 30, 2017, to submit a complete plan. A state that is developing a plan that includes a multi-state approach would have until June 30, 2018, to submit a complete plan.
The EPA is further proposing, as part of the emission guidelines, to allow states the option of translating the EPA-determined goal, which will be rate-based, to a mass-based goal. For states participating in a multi-state approach, the individual state performance goals in the emission guidelines would be replaced with an equivalent multi-state performance goal. The EPA is also proposing that in their plans, whether single state or multi-state, states may not adjust the stringency of the goals set by the EPA.
Under CAA section 111(d)(1) and the implementing regulations, with the state emission performance level in place, the state must adopt a state plan that establishes a standard of performance or set of standards of performance, along with implementing and enforcing measures, that will achieve that emission performance level. The EPA is further proposing, as part of the guidelines, to authorize the state to submit either of two types of measures to achieve the performance level: (1) A set of measures that we refer to as “portfolio” measures, which include a combination of emission limitations that apply directly to the affected sources and other measures that have the effect of limiting generation by, and therefore emissions from, the affected sources; or (2) solely emission limitations that apply directly to the affected sources.
The EPA is also proposing, as part of the plan guidelines, that a complete state plan include the following twelve components:
The EPA is also proposing, as part of its emission guidelines, that plan approvability be based on four general criteria: (1) Enforceable measures that reduce EGU CO
The EPA is also proposing, as part of its plan guidelines, requirements for the process and timing for demonstrating achievement of the required emission performance level, including performance and emission milestones. The proposed option would require each state to achieve its ultimate CO
If a state with affected EGUs does not submit a plan or if the EPA does not approve a state's plan, then under CAA section 111(d)(2)(A), the EPA must establish a plan for that state. A state that has no affected EGUs must document this in a formal letter submitted to the EPA by June 30, 2016. In the case of a tribe that has one or more affected EGUs in its area of Indian country,
This proposed action is consistent with the requirements of CAA section 111(d) and the implementing regulations. As an initial matter, the EPA reasonably interprets the provisions identifying which air pollutants are covered under CAA section 111(d) to authorize the EPA to regulate CO
A key step in promulgating requirements under CAA section 111(d) is determining the “best system of emission reduction . . . adequately demonstrated” (BSER). In promulgating the implementing regulations, the EPA explicitly stated that it is authorized to determine the BSER;
The EPA is proposing two alternative BSER for fossil fuel-fired EGUs, each of which is based on methods that have already been employed for reducing emissions of air pollutants, including, in some cases, CO
Further, these measures meet the criteria in CAA section 111(a)(1) and the caselaw as the “best” system of emission reduction because, among other things, they achieve the appropriate level of reductions, they are of reasonable cost, and they encourage technological development that is important to achieving further emission reductions. Moreover, the measures in each of the building blocks are “adequately demonstrated” because they are each well-established in numerous states, and many of them have already been relied on to reduce GHGs and other air pollutants from fossil fuel-fired EGUs. It should be emphasized that these measures are consistent with current trends in the electricity sector.
For the alternative approach for the BSER, the EPA is identifying the “system of emission reduction” as including, in addition to building block 1, the reduction of affected fossil fuel-fired EGUs' mass emissions achievable through reductions in generation of specified amounts from those EGUs. Under this approach, the measures in building blocks 2, 3, and 4 would not be components of the system of emission reduction, but instead would serve as bases for quantifying the reduction in emissions resulting from the reduction in generation at affected EGUs. In light of the available sources of replacement generation through the measures in the building blocks, this approach would also meet the criteria for being the “best” system that is “adequately demonstrated” because of the emission reductions it would
After determining the BSER, the EPA is authorized under the implementing regulations, as an integral component to setting emission guidelines, to apply the BSER and determine the resulting emission limitation. The EPA is proposing to apply the BSER to the affected EGUs on a statewide basis. In this rulemaking, the EPA terms the resulting emission limitation the state goal.
With the promulgation of the emission guidelines, each state must develop a plan to achieve an emission performance level that corresponds to the state goal. The state plans must establish standards of performance for the affected EGUs and include measures that implement and enforce those standards. Based on requests from stakeholders, the EPA is proposing that states be authorized to submit state plans that do not impose legal responsibility on the affected EGUs for the entirety of the emission performance level, but instead, by adopting what this preamble refers to as a “portfolio approach,” impose requirements on other affected entities (e.g., renewable energy and demand-side energy efficiency measures) that would reduce CO
It should be noted that an important aspect of the BSER for affected EGUs is that the EPA is proposing to apply it on a statewide basis. The statewide approach also underlies the required emission performance level, which, as noted, is based on the application of the BSER to a state's affected EGUs, and which the suite of measures in the state plan, including the emission standards for the affected EGUs, must achieve overall. The state has flexibility in assigning the emission performance obligations to its affected EGUs, in the form of standards of performance—and, for the portfolio approach, in imposing requirements on other entities—as long as, again, the required emission performance level is met.
This state-wide approach both harnesses the efficiencies of emission reduction opportunities in the interconnected electricity system and is fully consistent with the principles of federalism that underlie the Clean Air Act generally and CAA section 111(d) particularly. That is, this provision achieves the emission performance requirements through the vehicle of a state plan, and provides each state significant flexibility to take local circumstances and state policy goals into account in determining how to reduce emissions from its affected sources, as long as the plan meets minimum federal requirements. This state-wide approach, and the standards of performance for the affected EGUs that the states will establish through the state-plan process, are consistent with the applicable CAA section 111 provisions.
A state has discretion in determining the measures in its plans. The state may adopt measures that assure the achievement of the required emission performance level, and is not limited to the measures that the EPA identifies as part of the BSER. By the same token, the affected EGUs, to comply with the applicable standards of performance in the state plan, may rely on any efficacious means of emission reduction, regardless of whether the EPA identifies those measures as part of the BSER.
In this rulemaking, the EPA proposes reasonable deadlines for state plan submission and the EPA's action. The proposed deadline for the EPA's action on state plan submittals varies from that in the implementing regulations, and the EPA is proposing to revise that provision in the regulations accordingly. Under CAA section 111(d)(2), the state plans must be “satisfactory” for the EPA to approve them, and in this rulemaking, the EPA is proposing the criteria that the state plans must meet under that requirement.
The EPA discusses its legal interpretation in more detail in other parts of this preamble and discusses certain issues in more detail in the Legal Memorandum included in the docket for this rulemaking. The EPA solicits comment on all aspects of its legal interpretations, including the discussion in the Legal Memorandum.
The EPA has the authority to regulate, under CAA section 111(d), CO
During the 1990 CAA Amendments, the House of Representatives and the Senate each passed an amendment to CAA section 111(d)(1)(A)(i). The two amendments differed from each other, and were not reconciled during the Conference Committee and, as a result, both were enacted into law. As amended by the Senate, the pertinent language of CAA section 111(d)(1) would exclude the regulation of any pollutant which is “included on a list published under [CAA section] 112(b).”
It should be noted that the U.S. Supreme Court's holding in
We discuss this issue in more detail in the Legal Memorandum.
Before the EPA finalizes this CAA section 111(d) rule, the EPA will finalize a CAA section 111(b) rulemaking regulating CO
CAA section 111(d)(1) requires the EPA to promulgate regulations under which states must submit state plans regulating “any existing source” of certain pollutants “to which a standard of performance would apply if such existing source were a new source.” A “new source” is “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under [CAA section 111] which will be applicable to such source.” It should be noted that these provisions make clear that a “new source” includes one that undertakes either new construction or a modification. It should also be noted
Under CAA section 111(d)(1), in order for existing sources to become subject to that provision, the EPA must promulgate standards of performance under CAA section 111(b) to which, if the existing sources were new sources, they would be subject. Those standards of performance may include ones for sources that undertake new construction, modifications, or reconstructions.
The EPA is in the process of promulgating two rulemakings under CAA section 111(b) for CO
The EPA is proposing that, for the emission guidelines, an affected EGU is any fossil fuel-fired EGU that was in operation or had commenced construction as of January 8, 2014, and is therefore an “existing source” for purposes of CAA section 111, and that in all other respects would meet the applicability criteria for coverage under the proposed GHG standards for new fossil fuel-fired EGUs (79 FR 1430; January 8, 2014).
The January 8, 2014 proposed GHG standards for new EGUs generally define an affected EGU as any boiler, integrated gasification combined cycle (IGCC), or combustion turbine (in either simple cycle or combined cycle configuration) that (1) is capable of combusting at least 250 million Btu per hour; (2) combusts fossil fuel for more than 10 percent of its total annual heat input (stationary combustion turbines have an additional criteria that they combust over 90 percent natural gas); (3) sells the greater of 219,000 MWh per year and one-third of its potential electrical output to a utility distribution system; and (4) was not in operation or under construction as of January 8, 2014 (the date the proposed GHG standards of performance for new EGUs were published in the
The rationale for this proposal concerning applicability is the same as that for the January 8, 2014 proposal, sections V.A-B. See 79 FR at 1,459/1-1,461/2. We incorporate that discussion by reference here.
As noted in Section II.D of this preamble, although affected EGUs located in Indian country operate as part of the interconnected system of electricity production and distribution, affected EGUs located in Indian country within a state's borders would not be encompassed within the state's CAA section 111(d) plan. The EPA is aware of four potentially affected power plants located in Indian country: The South Point Energy Center, on Fort Mojave tribal lands within Arizona; the Navajo Generating Station, on Navajo tribal lands within Arizona; the Four Corners Power Plant, on Navajo tribal lands within New Mexico; and the Bonanza Power Plant, on Ute tribal lands within Utah. The South Point facility is an NGCC power plant, and the Navajo, Four Corners, and Bonanza facilities are coal-fired power plants. The operators and co-owners of these four facilities include investor-owned utilities, cooperative utilities, public power agencies, and independent power producers, most of which also co-own potentially affected EGUs within state jurisdictions. We are not aware of any potentially affected EGUs that are owned or operated by tribal entities. If it determines that such a plan is necessary or appropriate, the EPA has the responsibility to establish CAA section 111(d) plans for areas of Indian country where affected sources are located unless a tribe on whose lands an affected source (or sources) is located seeks and obtains authority from the EPA to establish a plan itself, pursuant to the Tribal Authority Rule.
The EPA invites comment on whether a tribe wishing to develop and implement a CAA section 111(d) plan should have the option of including the EGUs located in its area of Indian country in a multi-jurisdictional plan with one or more states (i.e., treating the tribal lands as an additional state).
If the EPA develops one or more CAA section 111(d) federal plans for areas of Indian country with affected EGUs, we are likewise currently considering doing so on a multi-jurisdictional basis in coordination with nearby states developing section 111(d) state plans. The EPA solicits comment on such an approach for a federal plan.
At this time, the EPA is not proposing CO
The state-specific goals that the EPA is proposing are based on the collection of affected EGUs located within that state. In setting goals specific to an area of Indian country, the EPA proposes to base the goals on the collection of affected EGUs located within that area of Indian country. We request comment on this approach.
In this rulemaking, the EPA is soliciting comment on combining the two existing categories for the affected EGUs into a single category for purposes of facilitating emission trading among sources in both categories. The EPA is also proposing codifying all of the proposed requirements for the affected EGUs in a new subpart UUUU of 40 CFR part 60.
As discussed in the January 8, 2014 proposal for the CAA section 111(b) standards for GHG emissions from EGUs, in 1971 the EPA listed fossil fuel-fired steam generating boilers as a new category subject to section 111 rulemaking, and in 1979 the EPA listed fossil fuel-fired combustion turbines as a new category subject to the CAA section 111 rulemaking. In the ensuing years, the EPA has promulgated standards of performance for the two categories, and codified those standards, at various times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. In the 2014 proposal, the EPA proposed separate standards of performance for sources in the two categories and proposed codifying the standards in the same Da and KKKK subparts that currently contain the standards of performance for conventional pollutants from those sources. In addition, the EPA co-proposed combining the two categories into a single category solely for purposes of the CO
In the present rulemaking, the EPA is proposing emission guidelines for the two categories and is soliciting comment on combining the two categories into a single category for purposes of the CO
In addition, the EPA is proposing to create a new subpart UUUU and to include all GHG emission guidelines for the affected sources—utility boilers and IGCC units as well as natural gas-fired stationary combustion turbines—in that newly created subpart. We believe that combining the emission guidelines for affected sources into a new subpart UUUU is appropriate because the emission guidelines the EPA is establishing do not vary by type of source. Accordingly, the EPA is not proposing to codify any of the requirements of this rulemaking in subparts Da or KKKK.
Based on the experiences of states and the industry and the EPA's outreach with stakeholders as described above, the EPA has identified multiple measures currently in use for achieving CO
As discussed in Section III of this preamble, we are mindful of numerous and varied stakeholder concerns, including the need to achieve meaningful CO
Similarly, we recognize and appreciate that states operate with differing circumstances and policy preferences. For example, states have differing access to specific fuel types, and the variety of types of EGUs operating in different states is broad and significant. States are part of assorted EGU dispatch systems and vary in the amounts of electricity that they import and export. For these reasons, we also recognize and appreciate the value in allowing and promoting multi-state reduction strategies. Some states already participate in a multi-state program that reduces CO
Another key consideration in determining the BSER, as discussed more in the following sections, is the relationship between the timing of measures and their effectiveness in limiting emissions. For example, actions that can occur in the near term, such as improvements to individual EGU heat rates, may fail to achieve the cumulative emission reductions that sustained implementation of other actions, such as demand-side energy efficiency programs, may achieve over time.
This subsection summarizes the EPA's analytic approach to determining the best system of emission reduction (BSER) for CO
“No technology, or level of emission reduction, solely by reason of the use of the technology, or the achievement of the emission reduction, by 1 or more facilities receiving assistance under this Act, shall be considered to be—(1) adequately demonstrated for purposes of section 111 of the Clean Air Act (42 U.S.C. 7411)[.]”
In a February 26, 2014 Notice of Data Availability, the EPA proposed to give this provision its natural meaning: the term “solely” modifies all of the provisions, so that any “adequately demonstrated” finding by the EPA could not be based solely upon technology, level of emission reduction, or achievement of the emission reduction by a facility (or facilities) receiving assistance. The EPA proposes the same interpretation here. The EPA further believes that its proposed determination of the “best system of emission reduction . . . adequately demonstrated” does not depend exclusively on technology, level of emission reduction, or achievement of emission reduction from facilities receiving EPAct assistance, given the myriad number of technologies and emission performance on which that proposed determination is based.
In considering the appropriate scope of the proposed BSER, the EPA evaluated three basic groupings of strategies for reducing CO
As described in the remainder of this section, the EPA concluded that while certain strategies within the first grouping clearly should be part of the BSER, it was not appropriate to limit consideration of the BSER to this first grouping, for several reasons. First, we determined that some strategies available in the other two groupings can support reduced CO
The first grouping of CO
Our assessment of heat rate improvements showed that these measures would achieve CO
The EPA also examined application of CCS technology at existing EGUs. CCS offers the technical potential for CO
Natural gas co-firing or conversion at coal-fired steam EGUs offers greater potential CO
The second grouping of CO
NGCC units can produce as much as 46 percent more electricity from a given quantity of natural gas than steam EGUs,
Our analysis indicated that the potential CO
As discussed below in Section VI.C.2, the data and considerations cited above support our assessment that an average NGCC utilization rate in a range of 65 to 75 percent is a reasonable target for the amount of additional NGCC generation that could be substituted for higher carbon generation from steam EGUs as part of the BSER.
Finally, we also note that mechanisms for encouraging re-dispatch as a CO
The third grouping of CO
Low-and zero-carbon generating capacity provides electricity that can be substituted for generation from more carbon-intensive EGUs. More than half the states already have established some form of state-level renewable energy requirements, with targets calling on average for almost 20 percent of 2020 generation to be supplied from renewable sources. The EPA is unaware of analogous state policies to support development of new nuclear units, but 30 states already have nuclear EGUs (with five units under construction) and the generation from these units is currently helping to avoid CO
Demand-side energy efficiency programs produce electricity-dependent services with less electricity, and thereby support reduced generation from existing fossil fuel-fired EGUs by reducing the demand for that generation. Reduced generation results in lower CO
Based on the analytic approach summarized above, the EPA has identified the following four principal categories—“building blocks”—of measures that provide the foundation of our BSER determination for CO
1. Reducing the carbon intensity of generation at individual affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs in the amount that results from substituting generation at those EGUs with generation from less carbon-intensive affected EGUs (including NGCC units under construction).
3. Reducing emissions from affected EGUs in the amount that results from substituting generation at those EGUs with expanded low- or zero-carbon generation.
4. Reducing emissions from affected EGUs in the amount that results from the use of demand-side energy efficiency that reduces the amount of generation required.
Since they either result in improved operating efficiency or support reductions in mass emissions at existing EGUs, each of the four building blocks represents a demonstrated basis for reducing CO
In this subsection we discuss each of the building blocks in turn. For each building block, we provide our proposed assessment of the technical potential of the building block and the reasonableness of its costs within the context of the BSER determination, and we describe how we developed the data inputs used in the computations of the proposed state goals described in Section VII.C and the alternate goals offered for comment in Section VII.E. We also discuss certain measures that we are not proposing to consider as part of the best system of emission reduction. Additional detail is provided
It is worth noting that although the discussion below necessarily addresses the building blocks individually, states are not required to pursue plans involving any given building block or to do so at any particular level of stringency. Rather, states have flexibility to establish plans to meet their state emission limitations using their own preferred combinations of efficacious measures applied to the extent determined appropriate by the states. The EPA expects that states and affected EGUs are unlikely to limit themselves to the measures in any single building block, but instead are likely to pursue portfolios of measures from a combination of the actions encompassed in the building blocks. In developing the data inputs to be used in computing state goals, the EPA has estimated reasonable rather than maximum possible implementation levels for each building block in order to establish overall state goals that are achievable while allowing states to take advantage of the flexibility to pursue some building blocks more extensively, and others less extensively, than is reflected in the goal computations, according to each state's needs and preferences.
The first category of approaches to reducing CO
The EPA is aware of the potential for “rebound effects” from improvements in heat rates at individual EGUs. In this context, a rebound effect would occur where, because of an improvement in its heat rate, an EGU experiences a reduction in variable operating costs that makes the EGU more competitive relative to other EGUs and consequently raises the EGU's generation output. The increase in the EGU's CO
Although heat rate improvements have the potential to reduce CO
The heat rate of an EGU is the amount of fuel energy input needed (Btu, higher heating value basis) to produce 1 kWh of net electrical energy output (and useful thermal energy in the case of cogeneration units).
Several studies have examined the opportunities to employ heat rate improvements as a means of reducing CO
In addition to the Sargent & Lundy study, which looked generically at the types of improvements that can be made at specific types of EGUs, historical heat rate data also provides a basis for
In order to estimate the technical potential of heat rate improvement opportunities at existing fossil fuel-fired EGUs suggested by the discussion above, the EPA pursued two principal areas of analysis. The first area concerned the heat rate improvements that could be achieved by reducing heat rate variability at individual coal-fired EGUs through adoption of best practices for operation and maintenance. The second area concerned heat rate improvement opportunities that could be achieved through further equipment upgrades. Both analyses are summarized below along with our conclusions, and are discussed in greater detail in the GHG Abatement Measures TSD.
For the best practices analysis, the EPA worked with the hourly data reported to the EPA by affected EGUs subject to the monitoring and reporting requirements of 40 CFR Part 75. The reported data include hourly heat input and, for most reporting EGUs, hourly gross generation, making it possible to compute hourly gross heat rates. We used the hourly data to assess variability in the hourly gross heat rates of approximately 900 individual coal-fired steam EGUs over the period from 2002 to 2012. Specifically, the EPA evaluated the consistency with which individual EGUs maintained their hourly heat rates over time. We expected that a certain degree of short-term heat rate variability was caused by factors beyond operators' control, notably variation in hourly ambient temperature and hourly load, and preliminary analysis confirmed our expectation. We therefore controlled for variation in those factors by grouping the observed hourly heat rate data for each EGU into subsets corresponding to ranges of hourly ambient temperatures and hourly load levels.
For the equipment upgrade analysis, we evaluated potential opportunities to improve heat rates at affected EGUs through specific upgrades identified in the 2009 Sargent & Lundy study. In that study, Sargent & Lundy estimated ranges of potential heat rate improvement achievable through a variety of equipment upgrades. We screened the upgrades from the study to identify what we consider to be a reasonable subset of equipment upgrades that would generally be beyond the scope of investments we would expect to be made for purposes of achieving the best-practices heat rate improvements discussed above. Based on the average of the study's ranges of potential heat rate improvements from the various upgrades in this subset, implementation of the full subset of appropriate opportunities at a single EGU could be expected to result in an aggregate heat rate improvement of approximately four percent (incremental to the improvement achievable from adoption of best practices). However, we recognize that this total may overstate the average equipment upgrade opportunity across all EGUs because some EGUs may have already implemented some of these upgrades. We therefore propose to use as a data input for purposes of developing state goals an estimate that, on average across the fleet of affected EGUs, only half of the full equipment upgrade opportunity just described remains—i.e., that for the fleet of affected EGUs as a whole, the technical potential for heat rate improvements from equipment upgrades incremental to the best-practices opportunity is on average two percent rather than four percent. We solicit comment on increasing this figure up to four percent.
Some of the measures available to EGUs for reducing their carbon intensity affect net heat rates rather than gross heat rates. Various EGU components such as pumps, fans, motors, and pollution control devices use electricity, a factor that is not accounted for in gross heat rates (that is, fuel used per unit of gross energy output) but is accounted for in net heat rates (that is, fuel used per unit of net energy output sent to the electric grid or used for thermal purposes). The electricity used by these components, referred to as auxiliary or parasitic load, may represent from 4 to 12 percent of gross generation at a coal-fired steam EGU.
The total of the estimated potential heat rate improvements from adoption of best practices to reduce heat rate variability and implementation of equipment upgrades as discussed above is six percent. This total is used as the data input for heat rate improvements in the computation of proposed state goals discussed in Section VII.C below. Because of the close relationship between an EGU's fuel consumption and its CO
For purposes of developing the alternate set of goals on which we are taking comment, as described in Section VII.E below, we have used a more conservative estimate of a four percent heat rate improvement from affected coal-fired EGUs on average. This level of improvement would be consistent with those EGUs on average implementing best practices to reduce heat rate variability without making further equipment upgrades, or would be consistent with those EGUs on average implementing both best practices and equipment upgrades, but to a lesser degree than we have projected as being achievable for purposes of our proposal. We view the four percent estimate as a reasonable minimum estimate of the technical potential for heat rate improvement on average across affected coal-fired steam EGUs.
By definition, any heat rate improvement made for the purpose of reducing CO
The EPA's most detailed estimates of the average costs required to achieve the full range of heat rate improvements come from the 2009 Sargent & Lundy study discussed above. Based on the study, the EPA estimated that for a range of heat rate improvements from 415 to 1205 Btus per kWh, corresponding to percentage heat rate improvements of 4 to 12 percent for a typical coal-fired EGU, the required capital costs would range from $40 to $150 per kW. To correspond to the average heat rate improvement of six percent that we have estimated to be achievable through the combination of best practices and equipment upgrades, we have estimated an average cost of $100 per kW, slightly above the midpoint of the Sargent & Lundy study's range. At an estimated annual capital charge rate of 14.3 percent, the carrying cost of an estimated $100 per kW investment would be $14.30 per kW-year. For a coal-fired EGU with a heat rate of 10,450 Btu per kWh, a utilization rate of 78 percent, and a coal price of $2.62 per MMBtu, a six percent heat rate improvement would produce fuel cost savings of approximately $11.20 per kW-year,
The EPA recognizes that the simplified cost analysis just described will represent the costs for some EGUs better than others because of differences in EGUs' individual circumstances. We further recognize that reductions in the utilization rates of coal-fired EGUs anticipated from other components proposed for inclusion in the best system of emission reduction would tend to reduce the fuel savings associated with heat rate improvements, thereby raising the effective cost of achieving the CO
Based on the analyses of technical potential and cost summarized above, we propose to find that a six percent reduction in the CO
We invite comment on all aspects of our analyses and findings related to heat rate improvements, both as summarized here and as further discussed in the Greenhouse Gas Abatement Measures TSD. As noted earlier, we specifically request comment on increasing the estimates of the amounts of heat rate improvement achievable through adoption of best practices for operation and maintenance and through equipment upgrades up to six percent and four percent, respectively, representing a total potential improvement of up to ten percent, particularly in light of the reasonable cost of heat rate improvements. We also solicit comment on the quantitative impacts on the net heat rates of coal-fired steam EGUs of operation at loads less than the rated maximum unit loads.
The second element of the foundation for the EPA's BSER determination for reducing CO
The nation's EGUs are interconnected by transmission grids extending over large regions. EGU owners and grid operators, subject to various reliability and operational constraints, use the flexibility provided by these interconnections to prioritize among available EGUs when deciding which units should be called upon (i.e., “dispatched”) to increase or decrease generation in order to meet electricity demand at any point in time. Recognizing that increments of generation are to some extent interchangeable, dispatch decisions are based on electricity demand at a given point in time, the variable costs of available generating resources, and system constraints. This system of security-constrained economic dispatch assures reliable and affordable electricity. Electricity demand varies across geography and time in response to numerous conditions, such that EGU owners and grid operators are constantly responding to changes in demand and “re-dispatching” to meet demand in the most reliable and cost-effective manner possible. Since the enactment and implementation of Title IV of the CAA Amendments of 1990, in regions where EGUs are subject to market-based programs to limit emissions of pollutants such as SO
We have also analyzed potential upstream net methane emissions impact from natural gas and coal for the impacts analysis. This analysis indicated that any net impacts from methane emissions are likely to be small compared to the CO
Having identified replacing generation at higher-emitting EGUs with generation at lower-emitting EGUs as a technically feasible CO
In order to estimate the potential magnitude of the opportunity to reduce power sector CO
We also researched historical data to determine the utilization rates that NGCC units have already been demonstrated capable of sustaining. Over the last several years, EGU owners and grid operators have engaged in considerable re-dispatch among various types of fossil fuel-fired units relative to historical dispatch patterns, with NGCC units increasing generation and many coal-fired EGUs reducing generation. In fact, in April 2012, for the first time ever the total quantity of electricity generated nationwide from natural gas was approximately equal to the total quantity of electricity generated nationwide from coal.
The experience of relatively heavily used NGCC units provides an additional indication of the degree of increase in average NGCC unit utilization that is technically feasible. According to the historical NGCC unit utilization rate data reported to the EPA, in 2012 roughly 10 percent of existing NGCC units operated at annual utilization rates of 70 percent or higher.
For purposes of establishing state goals, historical (2012) electric generation data are used to apply each building block and develop each state's goal (expressed as an adjusted CO
Although producing over 1,400 TWh of generation in 2020 from existing NGCC units is not actually required, because states may choose other abatement measures to reach the state goals, the EPA nevertheless believes that producing this quantity of generation from this set of NGCC units is feasible. As a reference point, NGCC generation increased by approximately 430 TWh (an 80 percent increase) between 2005 and 2012. The EPA calculates that NGCC generation in 2020 could increase by approximately 50 percent from today's levels. This reflects a smaller ramp-up rate in NGCC generation than has been observed from 2005 to 2012. We also expect an increase in NGCC generation of this amount would not impair power system reliability. As we note in the TSD on Resource Adequacy and Reliability, the level of potential re-dispatch can be accommodated within the flexible compliance requirements of the rule. Similar conclusions have been reached in recent studies of the potential impact of emission reductions from existing power plants.
The EPA also examined the technical capability of the natural gas supply and delivery system to provide increased quantities of natural gas and the capability of the electricity transmission system to accommodate shifting generation patterns. For several reasons, we conclude that these systems would be capable of supporting the degree of increased NGCC utilization needed for states to achieve the proposed goals. First, the natural gas pipeline system is already supporting national average NGCC utilization rates of 60 percent or higher during peak hours, which are the hours when constraints on pipelines or electricity transmission networks are most likely to arise. NGCC unit utilization rates during the range of peak daytime hours from 10 a.m. to 9 p.m. are typically 15 to 20 percentage points above their average utilization rates (which have recently been in the range of 40 to 50 percent).
We recognize that re-dispatch does contemplate an associated increase in natural gas production, consistent with the current trends in the natural gas industry. The EPA expects the growth in NGCC generation assumed in goal-setting to be feasible and consistent with domestic natural supplies. Increases in the natural gas resource base have led to fundamental changes in the outlook for natural gas. There is general agreement that recoverable natural gas resources will be substantially higher for the foreseeable future than previously anticipated, exerting downward pressure on natural gas prices. According to EIA, proven natural gas reserves have doubled between 2000 and 2012. Domestic production has increased by 32 percent over that same timeframe (from 19.2 TCF in 2000 to 25.3 TCF in 2012). EIA's Annual Energy Outlook for 2014 projects that production will further increase to 29.1 TCF, as a result of increased supplies and favorable market conditions. For comparison, NGCC generation growth of 450 TWh (calculated in goal setting) would result in increased gas consumption of roughly 3.5 TCF for the electricity sector, which is less than the projected increase in natural gas production.
The EPA notes that the assessments described above regarding the ability of the electricity and natural gas industries to achieve the levels of performance indicated for building block 2 in the state goal computations are supported by analysis that has been conducted using the Integrated Planning Model (IPM). IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector that the EPA has used for over two decades to evaluate the economic and emission impacts of prospective environmental policies. To fulfill its purpose of producing projections related to the electric power sector and its related markets—including least-cost capacity expansion and electricity dispatch projections—that reflect industry conditions in as realistic a manner as possible, IPM incorporates representations of constraints related to fuel supply, transmission, and unit dispatch. The model includes a detailed representation of the natural gas pipeline network and the capability to project economic expansion of the network based on pipeline load factors. At the EGU level, IPM includes detailed representations of key operational limitations such as turn-down constraints, which are designed to account for the cycling capabilities of EGUs to ensure that the model properly reflects the distinct operating characteristics of peaking, cycling, and base load units.
As described in more detail below, the EPA used IPM to assess the costs of requiring increasing levels of re-dispatch from higher- to lower-emitting EGUs, and to that end, the EPA developed a series of modeling scenarios that explored shifting generation from existing coal-fired EGUs to existing NGCC units on a 1:1 basis within defined areas.
Having established the technical feasibility and quantification of replacing incremental generation at
The EPA has conducted two sets of extensive analyses to help inform the development of the state-specific emission goals described in this proposal, including analyses of the opportunity to reduce CO
The first set—the dispatch-only analyses—explored the magnitude and cost of potential opportunities to shift generation from existing coal-fired EGUs to existing NGCC units within defined areas. The purpose of analyzing these scenarios was to understand and demonstrate to what extent existing NGCC units could increase their dispatch at reasonable costs and without significant impacts on other economic variables such as the prices of natural gas and electricity. To evaluate how EGU owners and grid operators could respond to a state plan's possible requirements, signals, or incentives to re-dispatch from more carbon-intensive to less carbon-intensive EGUs, the EPA analyzed a series of scenarios in which the fleet of NGCC units nationwide was required, on average, to achieve a specified annual utilization rate.
The costs and economic impacts of the various scenarios were evaluated by comparing the total costs and emissions from each scenario to the costs and emissions from a business-as-usual scenario. For the scenario reflecting a 70 percent NGCC utilization rate, comparison to the business-as-usual case indicates that the average cost of the CO
However, we also note that the costs just described are higher than we would expect to actually occur in real-world compliance with this proposal's goals. One reason for this is that the 70 percent utilization rate in the scenario exaggerates the stringency with which building block 2 is actually reflected in each of the state goals: While the goal computation procedure uses 70 percent as a target NGCC utilization rate for all states, for only 29 states do the goals actually reflect reaching that target NGCC utilization, with the result that the average NGCC utilization rate reflected in the computed state goals is only 64 percent.
The EPA also analyzed dispatch-only scenarios where shifting of generation among EGUs was limited by state boundaries. In these scenarios with less re-dispatch flexibility, the cost of achieving the quantity of CO
We invite comment on whether the regional or state scenarios should be given greater weight in establishing the appropriate degree of re-dispatch to incorporate into the state goals for CO
We also conclude from our analyses that the extent of re-dispatch estimated in this building block can be achieved without causing significant economic impacts. For example, in both of the 70 percent NGCC unit utilization rate scenarios—with re-dispatch limited to regional and state boundaries, respectively—delivered natural gas prices were projected to increase by an average of no more than ten percent over the 2020-2029 period, which is well within the range of historical natural gas price variability.
However, for the same reasons discussed above with respect to estimated costs per ton of CO
Based on the analyses summarized above, the EPA proposes that for purposes of establishing state goals, a reasonable estimate regarding the degree of mass emission reductions achievable at fossil fuel-fired steam EGUs can be determined based on the degree to which electricity generation could be shifted from more carbon-intensive EGUs to less carbon-intensive EGUs within the state at reasonable cost through re-dispatch. The increment of emission reductions incorporated in this component of our proposed BSER determination is commensurate with an annual utilization rate for the state's NGCC units of up to 70 percent, on average across all the NGCC units in the state.
For purposes of the alternative set of goals on which we are seeking comment, we have used the less stringent target of a 65 percent average utilization rate for NGCC units. In 2012, approximately 16 percent of existing NGCC plants larger than 25 megawatts had utilization rates equal to or higher than this level. Also, as noted earlier, average NGCC utilization nationwide is already over 60 percent in some peak hours. We therefore view 65 percent as a reasonable lower-bound estimate of an achievable average NGCC utilization rate, and we would expect the costs and economic impacts from re-dispatch associated with a 65 percent NGCC utilization target to be lower than the costs and impacts associated with the 70 percent utilization target. Our cost analysis indicated that CO
As discussed above, in addition to analyzing the impacts of using the proposed 70 percent target utilization rate for existing NGCC units, the EPA has also performed preliminary analysis of the impacts of using a target utilization rate for existing NGCC units of 75 percent. That analysis showed that CO
We invite comment on these proposed findings and on all other issues raised by the discussion above and the related portions of the Greenhouse Gas Abatement Measures TSD.
The third element of the foundation for the EPA's BSER determination for reducing CO
Renewable electricity (RE) generating technologies are a well-established part of the U.S. power sector. In 2012, electricity generated from renewable technologies, including conventional hydropower, represented 12 percent of total U.S. electricity generation, up from 9 percent in 2005. More than half the states have established renewable portfolio standards (RPS) that require minimum proportions of electricity sales to be supplied with generation from renewable generating resources.
To estimate the CO
The EPA has not assumed any specific type of renewable generating technology for the best practices scenario. Also, the scenario is not an EPA forecast of renewable capacity development and neither establishes RPS requirements that any state must meet nor makes any determinations regarding allowable RE compliance measures. Rather, it represents a level of renewable resource development for individual states—with recognition of regional differences—that we view as reasonable and consistent with policies that a majority of states have already adopted based on their own policy objectives and assessments of feasibility and cost.
As noted above, renewable resource potential varies regionally. This geographic pattern is reflected in the existing RPS requirements of the various states. Recognizing this pattern, the EPA has grouped the states into six regions for purposes of developing the best
The best practices scenario for each state consists of increasing annual levels of RE generation estimated based on application of an annual RE growth factor to the state's historical RE generation, subject to a maximum RE generation target. The annual RE growth factors and maximum RE generation targets were developed separately for each of the six regions. Our procedure for determining these elements is described in the Greenhouse Gas Abatement Measures TSD and summarized below.
The EPA first quantified the amount of renewable generation in 2012 in each state. The EPA then summed these amounts for all states in each region to determine a regional starting level of renewable generation prior to implementation of the best practices scenario. Hydropower generation is excluded from this existing 2012 generation for purposes of quantifying BSER-related RE generation potential because building the methodology from a baseline that includes large amounts of existing hydropower generation could distort regional targets that are later applied to states lacking that existing hydropower capacity. The exclusion of pre-existing hydropower generation from the baseline of this target-setting framework does not prevent states from considering incremental hydropower generation from existing facilities (or later-built facilities) as an option for compliance with state goals.
Next, the EPA estimated the aggregate target level of RE generation in each of the six regions assuming that all states within each region can achieve the RE performance represented by an average of RPS requirements in states within that region that have adopted such requirements. For this purpose, the EPA averaged the existing RPS percentage requirements that will be applicable in 2020 and multiplied that average percentage by the total 2012 generation for the region. We also computed each state's maximum RE generation target in the best practices scenario as its own 2012 generation multiplied by that average percentage. (For some states that already have RPS requirements in place, these amounts are less than their RPS targets for 2030.)
For each region we then computed the regional growth factor necessary to increase regional RE generation from the regional starting level to the regional target through investment in new RE capacity, assuming that the new investment begins in 2017, the year following the initial state plan submission deadline,
Finally, we developed the annual RE generation levels for each state. To do this, we applied the appropriate regional growth factor to that state's initial RE generation level, starting in 2017, but stopping at the point when additional growth would cause total RE generation for the state to exceed the state's maximum RE generation target. For computation of the proposed state goals discussed in Section VII.C below, we used the annual amounts for the years 2020 through 2029. For computation of the alternate state goals discussed in Section VII.E below, on which we are seeking comment, we used the annual amounts for the years 2020 through 2024.
Alaska and Hawaii are treated as separate regions. Their RE targets are based on the lowest regional RE target among the continental U.S. regions and their growth factors are based upon historical growth rates in their own RE generation. We invite comment regarding the treatment of Alaska and Hawaii as part of this method.
For details on the regional targets and growth factors applied, please refer to Chapter 4 of the GHG Abatement Measures TSD.
The cumulative RE amounts for each state, represented as percentages of total generation, are shown in Table 6.
The EPA notes that for some states, the RE generation targets developed using the proposed approach are less than those states' reported RE generation amounts for 2012. We invite comment on whether the approach for quantifying the RE generation component of each state's goal should be modified to include a floor based on reported 2012 RE generation in that state.
This approach to quantification of a state's RE generation target does not explicitly account for the amount of fossil fuel-fired generation in that state. Without such an accounting, the application of this approach could yield, for a given state, an increase in RE generation that exceeds the state's reported 2012 fossil fuel-fired generation.
We note that with the exception of hydropower, the RE generation levels represent total amounts of RE generation, rather than incremental amounts above a particular baseline level. As a result, this RE generation can be supplied by any RE capacity regardless of its date of installation. This approach is therefore focused on quantifying the fulfillment of each state's potential for the deployment of RE as part of BSER using a methodology that does not require discriminating between RE capacity that was installed before or after any given date. Under this approach, states in a given region where a higher proportion of total generation has already been achieved from renewable resources are assumed to have less opportunity for deployment of additional renewable generation as part of the BSER framework informing state goals, in comparison to states in that region where the proportion of total generation achieved from renewable resources to date has been lower. That being said, the assumptions of RE generation used to develop the state goals do not impose any specific RE generation requirements on any state; they are only used to inform the quantification of state goals to which states may respond with whatever emission reduction measures are preferred.
With regard to hydropower, we seek comment regarding whether to include 2012 hydropower generation from each state in that state's “best practices” RE quantified under this approach, and whether and how the EPA should consider year-to-year variability in hydropower generation if such generation is included in the RE targets quantified as part of BSER. Chapter 4 of the GHG Abatement Measures TSD presents state RE targets both with and without the inclusion of each state's 2012 hydropower generation.
The EPA believes that RE generation at the levels represented in the best practices scenario can be achieved at reasonable costs. According to an EPA analysis based on EIA levelized costs, the cost to reduce emissions through RE ranges from $10 to $40 per metric ton of CO
While RPS requirements will continue to grow over time, the EPA does not expect this anticipated expansion to fall outside the historical norms of deployment or to create unusual pressure for cost increases. Full compliance with current RPS goals through 2035 would require approximately 4 to 4.5 GW of new renewable capacity per year. Average deployment of RPS-supported renewable capacity from 2007 to 2012 exceeded 6 GW per year.
We invite comment on this approach to treatment of renewable generating capacity as a basis for the best system of emission reduction adequately demonstrated and for quantification of state goals.
Additionally, the EPA is soliciting comment on an alternative approach to quantification of renewable generation to support the BSER. Unlike the proposed RE scenario described above that relies on a regional application of state RPS commitments, the alternative methodology relies on a state-by-state assessment of RE technical and market potential. The alternative approach is based on two sources of information: A metric representing the degree to which the technical potential of states to develop RE generation has already been realized, and IPM modeling of RE deployment at the state level under a scenario that reflects a reduced cost of building new renewable generating capacity.
The metric measuring realization of RE technical potential in a state compares each state's existing renewable generation by technology type with the technical potential for that technology in that state as assessed by the National Renewable Energy Laboratory (NREL).
While a benchmark RE development rate offers a useful metric to quantify the proportion of RE generation that would bring all states up to a designated proportion of RE generation that has been achieved in practice by certain states to date, such a metric does not explicitly take into account the cost that would be faced to reach the benchmark RE development rate in each state. In order to take this cost into account, for this alternative approach the EPA has paired the benchmark RE development rates described above with IPM modeling of RE deployment at the state level, based on a scenario reflecting a reduced cost of building new renewable generating capacity. The cost reduction for new RE generating capacity is intended to represent the avoided cost of other actions that could be taken instead to reduce CO
Under this alternative RE approach, the EPA would quantify RE generation for each technology in each state as the lesser of (1) that technology's benchmark rate multiplied by the technology's in-state technical potential, or (2) the IPM-modeled market potential for that specific technology. For example, if the benchmark RE development rate for solar generation is determined to be 12 percent, and the hypothetical state described above has a solar generation technical potential of 5,000 MWh/year, then the benchmark RE development level of generation for that state would be 600 MWh/year. If the IPM-modeled market potential for solar generation in that state is 750 MWh/year, then this approach would quantify solar generation for that state as the benchmark RE development level (600 MWh/year) because it is the lesser amount of those two measures.
Having quantified an amount of RE generation from each RE technology in each state, the EPA would then determine for each state a total level of RE generation that equals the sum of the generation quantified for each of the assessed RE technologies in that state. If the EPA were to adopt this alternative approach for quantifying RE in BSER, these total levels of RE generation for each state would be incorporated in state goals in place of the RE generation levels quantified using the proposed approach described above. Further methodological detail and state-level RE targets for this alternative approach are provided in the Alternative RE Approach TSD in the docket.
We invite comment on this alternative approach to quantification of RE generation to support the BSER. We note that the three specific requests for comment made above with respect to the proposed quantification approach—addressing, first, the possibility of a floor based on 2012 RE generation, second, the possibility of a limitation based on 2012 fossil fuel-fired generation and, third, the treatment of hydropower generation—apply to this alternative approach as well.
Finally, the EPA notes that the alternative RE approach described above is one of a number of possible methodologies for using technical and economic renewable energy potential to quantify RE generation for purposes of state goals. The EPA invites comment on other possible techno-economic approaches. For example, a conceptual framework for another techno-economic approach is provided in the Alternative RE Approach TSD.
Nuclear generating capacity facilitates CO
One way to increase the amount of available nuclear capacity is to build new nuclear EGUs. However, in addition to having low variable operating costs, nuclear generating capacity is also relatively expensive to build compared to other types of generating capacity, and little new nuclear capacity has been constructed in the U.S. in recent years; instead, most recent generating capacity additions have consisted of NGCC or renewable capacity. Nevertheless, five nuclear EGUs at three plants are currently under construction: Watts Bar 2 in Tennessee, Vogtle 3-4 in Georgia, and Summer 2-3 in South Carolina. The EPA believes that since the decisions to construct these units were made prior to this proposal, it is reasonable to view the incremental cost associated with the CO
Another way to increase the amount of available nuclear capacity is to preserve existing nuclear EGUs that might otherwise be retired. The EPA is aware of six nuclear EGUs at five plants that have retired or whose retirements have been announced since 2012: San Onofre Units 2-3 in California, Crystal River 3 in Florida, Kewaunee in Wisconsin, Vermont Yankee in Vermont, and Oyster Creek in New Jersey. While each retirement decision
We have determined that, based on available information regarding the cost and performance of the nuclear fleet, preserving the operation of at-risk nuclear capacity would likely be capable of achieving CO
For purposes of goal computation, generation from under-construction and preserved nuclear capacity is based on an estimated 90 percent average utilization rate for U.S. nuclear units, consistent with long-term average annual utilization rates observed across the nuclear fleet. The methodology for taking this generation into account for purposes of setting state emission rate goals is described below in Section VII on state goals and in the Goal Computation TSD.
We invite comment on all aspects of the approach discussed above. In addition, we specifically request comment on whether we should include in the state goals an estimated amount of additional nuclear capacity whose construction is sufficiently likely to merit evaluation for potential inclusion in the goal-setting computation. If so, how should we do so—for example, according to EGU owners' announcements, the issuance of permits, projections of new construction by the EPA or another government agency, or commercial projections? What specific data sources should we consider for those permits or projections?
The fourth element of the foundation for the EPA's BSER determination for reducing CO
Reducing demand for generation at affected EGUs through policies to improve demand-side energy efficiency is a proven basis for reducing CO
By reducing electricity consumption, energy efficiency avoids greenhouse gas emissions associated with electricity generation. Because fossil fuel-fired EGUs typically have higher variable costs than other EGUs (such as nuclear and renewable EGUs), their generation is typically the first to be replaced when demand is reduced. Consequently, reductions in the utilization of fossil fuel-fired EGUs can be supported by reducing electricity consumption and, by the same token, reductions in electricity consumption avoid the CO
To estimate the potential CO
We have not assumed any particular type of demand-side energy efficiency policy. States with leading energy efficiency performance have employed a variety of strategies that are implemented by a range of entities including investor-owned, municipal and cooperative electric utilities as well as state agencies and third-party administrators. These include energy efficiency programs,
While EM&V data reflect documented electricity savings from energy efficiency programs, they typically do not account for potential electricity savings available from additional state-implemented policies for which EM&V protocols are less consistently required or applied, such as building energy codes. Thus, we consider the 1.5 percent annual incremental savings
For states where EE program experience is more limited, reaching a best-practices level of performance requires undertaking a set of activities that takes some time to plan, implement, and evaluate. For the best practices scenario, we have therefore estimated that each state's annual incremental savings rate increases from its 2012 annual saving rate
As discussed in Section VII.E below, the EPA is also taking comment on a less stringent alternative for setting state goals. Under this alternative, the demand-side energy efficiency requirement uses 1.0 percent (rather than 1.5 percent) annual incremental savings as representative of the best-practices level of performance. In addition, the pace at which incremental savings levels are increased from their historical levels is relaxed slightly to 0.15 percent per year (rather than 0.2 percent). The 1.0 percent rate of savings is a level of performance that has been achieved—or that established state requirements will cause to be achieved—by 20 states.
The state-specific cumulative annual electricity saving data inputs for both the proposed approach and the less stringent alternative are discussed in the Greenhouse Gas Abatement Measures TSD and summarized in Table 7.
The EPA expects implementation of demand-side energy efficiency policies as reflected in the best practices scenario to be achievable at reasonable costs. The EPA finds support for the reasonableness of the costs of this building block from two perspectives. First, the specific savings levels represented by this building block were developed based upon the experience and success of states in developing and implementing energy efficiency policies that they undertake primarily for the purpose of providing economic benefits to electricity consumers in their state. Secondly, even with notably conservative assumptions about the costs of achieving the levels of electricity savings associated with this building block, the EPA's analysis of the power sector indicates that the costs are reasonable.
The processes by which states develop funding for energy efficiency programs typically require the application of cost-effectiveness tests to ensure that adopted program portfolios lead to lower costs than the use of generation sources that would otherwise be required to meet the associated electricity service demands. Indeed, a major reason for the widespread presence and rapid growth of demand-side energy efficiency programs is the strong evidence of the reasonableness of their costs even before the additional benefit of CO
Another approach to evaluating the reasonableness of the costs associated with this building block is to compare the demand-side energy efficiency costs to the avoided power system costs as represented within the EPA's modeling of the power sector. The costs associated with the best practices scenario were estimated based upon a synthesis of data and analysis of the factors that impact energy efficiency program costs as calculated using an engineering-based, bottom-up approach that is standard for state and utility analysis of these policies. These factors include the average energy efficiency program costs per unit of first-year energy savings ($/MWh), the ratio of program to participant costs, and the lifetimes of energy efficiency measures across the full portfolio of programs. In addition, the EPA has included a cost escalation factor to represent the possibility of increased costs associated with higher levels of incremental energy savings rates and the national scope of the best practices scenario. The EPA has taken a conservative approach to each of these factors, selecting values that are at the higher-cost end of reasonable ranges of estimated values. The combination of these factors is reflected in the value the EPA has derived for the levelized cost per MWh of saved energy. This value includes both the program costs paid by utilities for implementing energy efficiency programs and the amounts that program participants pay for their own energy efficiency improvements beyond the program costs. These costs are levelized across the measure lifetimes of a full portfolio of energy efficiency programs. This analysis provides a levelized cost of saved energy (LCOSE) range of $85/MWh to $90/MWh ($2011) over the 2020 to 2030 period. This range of LCOSE is notably conservative (leading to higher costs) in comparison with most utility and state analysis. For example, a 2014 analysis by the American Council for an Energy-Efficient Economy (ACEEE) surveyed program and participant cost results across seven states and found a comparable LCOSE value of $54/MWh (2011$).
To estimate the reductions in power system costs and CO
Further details regarding the data and methodology used to evaluate the potential for demand-side energy efficiency programs to substitute for generation at affected EGUs and thereby facilitate reductions of power sector CO
There are four additional potential measures for reducing, or supporting reduced, GHG emissions from EGUs that the EPA does not propose to consider part of the best system of emission reduction adequately demonstrated for existing EGUs at this time and therefore has not used for goal-setting purposes, but that merit discussion here: Fuel switching at individual EGUs, carbon capture and storage (CCS), using expanded amounts of less carbon-intensive new NGCC capacity to provide replacement generation, and heat rate improvements at affected EGUs other than coal-fired steam EGUs.
One technically feasible approach for reducing CO
Changing the type of fuel burned at a steam EGU typically requires certain plant modifications (e.g., new burners) and may have some negative impact on the net efficiencies of the boiler and the overall generation process. If the plant lacks existing gas pipeline infrastructure capable of delivering the necessary quantities of natural gas to the boiler, installation of a new pipeline lateral would also be required.
The capital costs of plant modifications required to switch a coal-fired EGU completely to natural gas are roughly $100-300/kW, excluding pipeline costs. For plants that require additional pipeline capacity, the capital cost of constructing new pipeline laterals is approximately $1 million per mile of pipeline built. Offsetting these capital costs, conversion to 100 percent gas input would typically reduce the EGU's fixed operating and maintenance costs by about 33 percent due mainly to certain equipment retirements and a reduction in staffing, while non-fuel variable costs would be reduced by about 25 percent due to reduced maintenance and waste disposal costs. However, in most cases, the most significant cost change associated with switching from coal to gas in a coal-fired boiler is likely to be the difference in fuel cost. Using EIA's projections of future coal and natural gas prices, switching a steam EGU's fuel from coal to gas typically would more than double the EGU's fuel cost per MWh of generation.
The CO
For a typical base-load coal-fired EGU, and reflecting EIA's projected future natural gas and coal prices, the average cost of CO
The EPA's economic analysis suggests that there are more cost effective opportunities for coal-fired utility boilers to reduce their CO
We solicit comment on whether natural gas co-firing or conversion should be part of the BSER. We also request comment regarding whether, and, if so, how, we should consider the co-benefits of natural gas co-firing in making that determination.
Another possible approach for reducing CO
In contrast, the EPA did not identify full or partial CCS as the BSER for new natural gas-fired stationary combustion turbines, noting technical challenges to implementation of CCS at NGCC units as compared to implementation at new solid fossil fuel-fired sources. The EPA also noted that, because virtually all new fossil fuel-fired power projects are projected to use NGCC technology, requiring full or partial CCS would have a greater impact on the price of electricity than requiring CCS at the few projected coal plants, and the larger number of NGCC projects would make a CCS requirement difficult to implement in the short term.
Partial CCS has been demonstrated at existing EGUs. It has been demonstrated at a pilot-scale at Southern Company's Plant Barry, it is being installed for large-scale demonstration at NRG's W.A. Parish facility, and it is expected soon to be applied at a commercial scale as a retrofit at SaskPower's Boundary Dam plant in Canada. However, the EPA expects that the costs of integrating a retrofit CCS system into an existing facility would be substantial. For example, some existing sources have a limited footprint and may not have the land available to add a CCS system. Moreover, there are a large number of existing fossil-fired EGUs. Accordingly, the overall costs of requiring CCS would be substantial and would affect the nationwide cost and supply of electricity on a national basis.
For the reasons just described, based on the information available at this time, the EPA does not propose to find that CCS is a component of the best system of emission reduction for CO
Additional discussion can be found in the Greenhouse Gas Abatement Measures TSD.
In Section VI.C.2 above, we discussed the opportunity to reduce CO
In addition, we note that our compliance modeling for this proposal suggests that the construction and operation of new NGCC capacity will be undertaken as method of responding to the proposal's requirements.
However, compared to the opportunity to reduce CO
The second reason that emission reductions from the use of new NGCC capacity would be more costly is that there would be capital investment costs. Some amount of new NGCC capacity (beyond the units that were already under construction as of January 8, 2014 and are “existing” units for purposes of this proposal) would likely be built to meet perceived electricity market demand or to replace less economic capacity regardless of this proposal. The costs of achieving CO
The third reason relates to the costs of pipeline infrastructure expansion, and in particular the unevenly distributed nature of those costs. While expanded use of existing NGCC capacity to achieve CO
Taken together, the EPA believes the cost considerations just described indicate a higher cost for CO
While the EPA is not proposing that new NGCC capacity is part of the basis supporting the BSER, we recognize that there are a number of new NGCC units being proposed and that many modeling efforts suggest that development of new NGCC capacity would likely be used as a CO
The EPA assessed opportunities to improve heat rates at affected EGUs other than coal-fired steam units. This assessment, which is documented in a Technical Memorandum included as an appendix to the GHG Abatement Measures TSD, considers the potential extent of heat rate improvements and CO
Finally, the EPA expects that for some individual oil/gas-fired steam EGUs and NGCC units attractive heat rate improvement opportunities will exist. We note that under the proposed flexible approach to state plans described later in this preamble, CO
This subsection summarizes the EPA's examination of combinations of the building blocks as components of the BSER, comparing the merits of a potential BSER that comprises only building blocks 1 and 2 with the merits of a BSER that comprises all four building blocks—the preferred option in this proposal. (A more detailed discussion of how we evaluated each option against the criteria to be considered for the BSER follows in Section VI.E.)
As previously described, the building blocks can be summarized as follows:
The EPA initially considered a BSER comprising only strategies within building block 1. As described earlier in Section VI.B, the EPA concluded that certain strategies within building block 1—specifically heat rate improvements at individual coal-fired steam EGUs—should be a component of the BSER determination, as they are technically feasible and can be implemented at a reasonable cost. However, the EPA further concluded that, while heat rate improvements qualify as a system of emission reduction, they are not in themselves the BSER as there are additional strategies that can be utilized in combination with building block 1 that are technically feasible, can be implemented at reasonable cost, and result in greater emission reductions than would be achieved through building block 1 strategies alone. The EPA is also concerned that if the measures that improve heat rates at coal-fired steam EGUs in building block 1 are implemented in isolation, without additional measures that reduce overall electricity demand or encourage substitution of less carbon-intensive generation for more carbon-intensive generation, the resulting increased efficiency of coal-fired steam units would provide incentives to operate those EGUs more, leading to smaller overall reductions in CO
We considered a BSER that comprises strategies from building blocks 1 and 2.
The EPA believes that the combination of building blocks 1 and 2 would be a “system of emission reduction” capable of achieving significant reductions in CO
Nevertheless, the EPA is not proposing that a combination of building blocks 1 and 2 is the BSER, because the proposed combination of all four building blocks discussed below—in other words, adding to the measures in building blocks 1 and 2 the measures in building blocks 3 and 4, which we and stakeholders have identified as already in use—is capable of achieving even greater CO
Our proposal for the BSER is a combination of all four building blocks. As discussed in Section VI.C above, each of the four building blocks is a proven way to support either improvements in emissions rates at affected EGUs or reductions in EGU mass emissions; each is in widespread use and is independently capable of supporting significant CO
In the large and highly integrated electricity system, where electricity is fungible and the demand for electricity services can be met in many ways (including through demand-side energy efficiency), states and the industry have long pursued a wide variety of strategies for ensuring that the demand for electricity services is met reliably, at reasonable costs, and in a manner consistent with evolving constraints, including environmental objectives. These strategies have long extended to the measures in all four building blocks. We believe the combination of all four building blocks fairly represents the range of measures that states and the industry will consider when developing state plans and strategies for reducing CO
In this section, the EPA explains the “best system of emission reduction . . . adequately demonstrated.” This explanation includes what the EPA proposes to determine as the BSER and why. In addition the EPA explains how the BSER forms the basis for each state's overall emission limitation requirement, which the EPA determines as the state goal and the state adopts into its planning process as the emissions performance level. The emission performance level, in turn, constitutes the minimum degree of stringency for the standards of performance that, taken as a whole, the state must establish for its affected EGUs (or, if the state adopts the portfolio approach, for the requirements imposed on the affected EGUs and other entities). Through this process, the BSER informs the minimum stringency of the standards of performance, although the state retains flexibility in its allocation of emission limitations among its sources. As the EPA explains, central to this overall approach is the fact that the EPA applies the BSER on a state-wide basis, which is consistent with the interconnected nature of the electricity system.
The EPA is proposing two alternative formulations for the BSER, each of which is based on, although in different ways, the four building blocks. Under the first approach, emission rate improvements and mass emission reductions at affected EGUs facilitated through the adoption of the four building blocks themselves meet the criteria for the BSER because they will amount to substantial reductions in CO
The remainder of this discussion is organized into the following subsections. Subsection 2 contains a summary of relevant considerations for the BSER as defined in the statute and further interpreted in court decisions. Subsection 3 discusses characteristics of the electricity industry relevant to
The EPA's explanation for this BSER proposal begins with the statutory definition of a “standard of performance”:
The term “standard of performance” means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.
The U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit or Court) has handed down case law over a 40-year period that interprets this CAA provision, including its component elements.
• The system of emission reduction must be technically feasible.
• The EPA must consider the amount of emission reductions that the system would generate.
• The costs of the system must be reasonable. The EPA may consider costs at the source level, the industry level, and, at least in the case of the power sector, the national level in terms of the overall costs of electricity and the impact on the national economy over time.
• The EPA must also consider that CAA section 111 is designed to promote the development and implementation of technology, including the diffusion of existing technology as the BSER,
Another consideration particularly relevant to this rulemaking is energy impacts, which, as with costs, the EPA may consider at the source level, the industry level, and the national level over time. In the context of the electricity industry and this proposal, the EPA believes that the scope of energy impacts that may be considered encompasses assurance of the continued ability of the industry to meet the evolving demand for electricity services in a reliable manner, while providing sufficient flexibility to enable affected sources to follow state energy plans.
Importantly, the EPA has discretion to weigh these various considerations, may determine that some merit greater weight than others, and may vary the weighting depending on the source category.
It is a well-established principle that states have discretion regarding the measures adopted in their state implementation plans under CAA section 110 to attain the NAAQS.
The EPA discussed the CAA requirements and Court interpretations of the BSER at length in the January 2014 Proposal, 79 FR at 1,462/1-1,467/3, and incorporates by reference that discussion into this rulemaking.
Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (i.e., phosphate fertilizer plants (fluorides), sulfuric acid plants (acid mist), primary aluminum plants (fluorides), Kraft pulp plants (total reduced sulfur), and municipal solid waste landfills (landfill gases)).
The U.S. electricity system is a highly interconnected, integrated system in which large numbers of EGUs using diverse fuels and generating technologies are operated in a coordinated manner to produce fungible electricity services for customers. Because electricity storage is costly and has not been widely deployed, the amounts of electricity demanded and supplied must be continuously matched, and system operators typically have flexibility to choose among multiple EGUs when selecting where to obtain the next MWh of generation needed. Coordination over short- and long-term time scales is accomplished through a variety of institutions including vertically integrated utilities, state regulatory agencies, independent system operators and regional transmission organizations (ISOs/RTOs), and market mechanisms. The electricity sector is both critical to the nation's economy and the source of more than 30 percent of U.S. greenhouse gas emissions, predominantly in the form of CO
The integrated electricity system allows increased generation from less carbon-intensive NGCC units to substitute for generation from more carbon-intensive steam EGUs (building block 2), thereby lowering CO
The integrated nature of the electricity system has long played a central role in the industry's continuing efforts to assure reliability and to manage costs generally. Specifically in the area of pollution control, state governments and the federal government have repeatedly taken advantage of the integrated nature of the electricity system when designing programs to allow the industry to meet the pollution control objectives in a least-cost manner. Examples include several cap-and-trade programs to reduce national or regional emissions of SO
Some states are already relying on the integrated nature of the electricity system to establish the policy contexts within which affected EGUs will reduce their CO
California enacted its Global Warming Solutions Act (also known as AB32) in 2006, requiring the state to reduce its GHG emissions to 1990 levels by 2020 and 80 percent below 1990 levels by 2050.
The Colorado Clean Air, Clean Jobs Act (CACJA), signed into law on April 19, 2010, required each investor-owned utility with coal-fired EGUs to submit to the state a multi-pollutant plan for meeting current and foreseeable EPA standards for emissions of NO
Multi-state mechanisms with analogous impacts on both longer-term planning decisions and short-term dispatch decisions have also been put in place. For example, nine northeastern and Mid-Atlantic States
An approach to determination of the BSER that recognizes the integrated nature of the electricity system is also consistent with the way in which the electricity industry already addresses resource planning issues. For example, in states where the price of EGUs' generation remains subject to regulation, utilities generally prepare integrated resource plans setting forth their strategies for meeting future demand for electricity services in a cost-effective manner. These plans may include measures from building blocks 2, 3, and 4. In most states where generation is no longer subject to price regulation, regional transmission organizations (RTOs) or independent system operators (ISOs) ensure the adequacy of future generation supplies by administering auctions for forward capacity. In these auctions, owners of existing EGUs (with consideration of building blocks 1 and 2),
As indicated by the foregoing discussion, in the U.S. electricity system the demand for electricity services is met, on both a short-term and longer-term basis and in both regulated and deregulated contexts, through integrated consideration of a wide variety of possible options, coordinated by some combination of utilities, regulators, system operators, and market mechanisms. The EPA believes that the BSER for CO
A final, important point regarding the integrated electricity system is that the sets of actions that enable the demand for electricity services to be continuously met can be undertaken in different orders, with changes in some interconnected elements eliciting compensating responses from other interconnected elements. Thus, the CO
Further discussion of the ways in which the “system of emission reduction” for affected EGUs is influenced by the interconnected and integrated nature of the electricity system is provided below in the context of the EPA's rationale for proposing to base the BSER on the combination of all four building blocks. This topic is also discussed in the Legal Memorandum available in the docket.
In this subsection we explain why (i) the individual building blocks meet the criteria to qualify as components of the “best system of emission reduction . . . adequately demonstrated” and (ii) why, under the alternative formulation of the BSER as including reduced utilization of higher-emitting affected EGUs in specified amounts, building blocks 2, 3, and 4 serve as the basis for those amounts and why the reduced utilization is “adequately demonstrated.”
Building block 1—reducing the carbon intensity of generation at individual affected coal-fired steam EGUs through heat rate improvements—is a component of the BSER because the measures the affected sources may
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of CO
Other BSER criteria also favor building block 1 as a component of the BSER. For example, with respect to non-air health and environmental impacts, heat rate improvements cause fuel to be used more efficiently, reducing the volumes of and therefore the adverse impacts associated with disposal of coal combustion solid waste products. With respect to technological innovation, building block 1 encourages the spread of more advanced technology to EGUs currently using components with older designs. The EPA has not specifically evaluated the extent to which enhanced maintenance practices leading to heat rate improvements might also lead to electricity reliability improvements, but generally expects that enhanced maintenance would be more likely to improve than to degrade EGU availability, which would tend to improve electricity system reliability.
As noted above, the EPA is concerned about the potential “rebound effect” associated with building block 1 if applied in isolation. More specifically, we noted that in the context of the integrated electricity system, absent other incentives to reduce generation and CO
Building block 2—reducing CO
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of CO
Both the achievability of this building block and the reasonableness of its costs are supported by the fact that there has been a long-term trend in the industry away from coal-fired generation and toward NGCC generation for a variety of reasons. As part of their CO
The emission reductions achievable or supported by the application of building block 2 also perform well against other BSER criteria. For example, we expect that building block 2 would have positive non-air health and environmental impacts. Coal combustion for electricity generation produces large volumes of solid wastes that require disposal, with some potential for adverse environmental impacts; these wastes are not produced by natural gas combustion. The intake and discharge of water for cooling at many EGUs also carries some potential for adverse environmental impacts; NGCC units generally require less cooling water than steam EGUs.
It should be observed that, by definition of the elements of this building block, the shifts in generation taking place under building block 2 occur entirely among existing EGUs subject to this rulemaking.
Finally, the EPA notes that the alternative interpretation of the BSER discussed later is based in part on the re-dispatch measures in building block 2. In this alternative, as it relates to building block 2, reduced generation from the subset of affected EGUs consisting of fossil fuel-fired steam EGUs—i.e., the most carbon-intensive subset of affected EGUs—is a component of the BSER. The potential to use increased generation from less carbon-intensive affected NGCC units would serve as a basis for quantifying the amounts of generation reductions and CO
Building block 3—reducing CO
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of the measures in building block 3 are discussed in Section VI.C.3 above. We consider all of these measures to be proven, well-established practices within the industry, and development of renewable capacity in particular is consistent with recent industry trends. States are already pursuing policies that encourage production of greater amounts of renewable energy, such as the establishment of targets for procurement of renewable generating capacity. Moreover, markets for renewable energy certificates, which facilitate investment in renewable energy, are already well-established. As noted above with re-dispatch, an allowance system or tradable emission rate system would provide incentives for sources to reduce their emissions as much as possible, including through substituting for their generation with generation from renewable energy. In addition, owners of existing nuclear units and nuclear units currently under construction can take action to complete or preserve that capacity, the generation from which likewise can be dispatched in a coordinated manner to substitute for fossil fuel-fired generation. As discussed above, coordination of these decisions in the integrated electricity system can occur through a variety of mechanisms, some centralized and some not.
The renewable capacity measures in building block 3 generally perform well against other BSER criteria. For example, incentives for expansion of renewable capacity encourage technological innovation in improved renewable technologies as well as more extensive deployment of current advanced technologies. Generation from wind turbines (the most common renewable technology) does not produce solid waste or require cooling water, a better environmental outcome than if that amount of generation had instead been produced at a typical range of fossil fuel-fired EGUs. Although the intermittent nature of generation from renewable resources such as wind and solar units requires special consideration from grid operators, renewable generation has grown quickly in recent years, as discussed above, and the EPA has seen no evidence that operators will be less able to cope with future growth than they have with rapid past growth.
The EPA believes that the performance of the nuclear measures in building block 3 against the other BSER measures is also positive on balance. With respect to encouragement of technological innovation, incentives for completion of nuclear capacity currently under construction encourage deployment of nuclear unit designs that reflect advances over earlier designs. The nation's nuclear fleet today routinely operates at high average utilization rates, suggesting no reason to expect adverse reliability consequences from completion or preservation of additional nuclear capacity. The five nuclear units currently under construction are all designed to use closed-cycle cooling systems with lower cooling water usage than some existing fossil fuel-fired EGUs;
Finally, the EPA notes that the alternative BSER discussed later would include a component consisting of reduced generation from affected EGUs,
Building block 4—reducing CO
The EPA's analysis and conclusions regarding the technical feasibility, costs, and magnitude of building block 4 are discussed in Section VI.C.4 above. We consider demand-side energy efficiency programs to be proven, well-established practices within the industry that are consistent with industry trends. Greater demand-side energy efficiency is already a common policy goal among states, and most states already authorize or require implementation of demand-side energy efficiency programs. Fossil fuel-fired EGUs can reduce their generation. Owners of affected EGUs as well as other parties can contract for demand-side energy efficiency. As discussed above, coordination of these decisions in the integrated electricity system can occur through a variety of mechanisms, some centralized and some not. For example, an allowance system or tradable emission rate system would provide incentives that promote the measures in building block 4 in the same manner as discussed above for other building blocks.
Building block 4 is also very attractive under other BSER criteria. Demand-side energy efficiency avoids the non-air health and environmental effects of the fossil fuel-fired generation for which it substitutes. Further, by reducing the overall amount of electricity that needs to be transmitted between EGUs and customers, demand-side energy efficiency tends to relieve stress on the grid, thereby increasing system reliability. Creating incentives for additional demand-side energy efficiency is also consistent with the goals of encouraging technological innovation in energy efficiency and encouraging deployment of current advanced technologies. For all these reasons, the measures in building block 4 qualify as a component of the “best system of emission reduction . . . adequately demonstrated.”
The EPA notes that the alternative BSER discussed later would include a component consisting of reduced generation from affected EGUs, with demand-side energy efficiency serving as a basis for quantifying the amounts of generation reductions and consequent CO
The EPA has considered whether a combination of building blocks 1 and 2 would be the BSER. As described in Section VI.D above, we believe that such a combination is technically feasible and would be a “system of emission reduction” capable of achieving meaningful reductions in CO
The EPA believes that both building blocks 1 and 2 individually satisfy the BSER criteria identified by the statute and the D.C. Circuit, with one possible concern, related to a “rebound effect,” noted earlier. That concern is the potential for the heat rate improvements in building block 1, if implemented in isolation, to make coal-fired steam EGUs more competitive compared to other EGUs and cause them to increase their generation, creating a “rebound effect” that would make building block 1 less effective at reducing CO
With respect to most of the BSER criteria, there is no reason to expect that the combination of building blocks 1 and 2 would be evaluated differently from the individual building blocks. However, as noted earlier, the combination addresses the concern about building block 1 regarding a potential rebound effect, and in that important respect it performs better than building block 1 considered in isolation. The substitution of NGCC generation for generation from coal-fired and other steam EGUs ensures that generation from coal-fired EGUs, as a group, would not increase as a result of their improved variable costs, with the result that the reduction in CO
While achieving substantially greater emission reductions than building block 1 alone, by reducing overall generation from coal-fired EGUs the combination of building blocks 1 and 2 also has the potential to raise the cost of the portion of the overall emission reductions achievable through heat rate improvements relative to the cost of those reductions if building block 1 were implemented in isolation.
As noted above, the EPA invites comment on a potential BSER comprising building blocks 1 and 2, in light of the considerations that could support this approach.
The EPA's proposed BSER is a combination of all four building blocks. For the reasons described below, and similar to each of the building blocks, the combination must be considered a “system of emission reduction.” Moreover, as also discussed below, the combination qualifies as the “best” system that is “adequately demonstrated.” The combination is technically feasible; it is capable of achieving meaningful reductions in CO
The assessments of the individual building blocks against the BSER criteria would generally apply in the same way to those building blocks when implemented as the combination of all four building blocks, with the same exceptions as discussed above with respect to the combination of building blocks 1 and 2 as well. However, the combination of all four building blocks would improve upon the combination of building blocks 1 and 2 in several respects. First, because of the potential of building blocks 3 and 4 to achieve additional CO
As has been discussed in earlier portions of the preamble, the costs and energy impacts of each of the four building blocks individually are reasonable when viewed either at the individual source level or through the lens of the electricity system as a whole, a conclusion that holds for the combination of the building blocks as well. Moreover, the flexibility available to states and regulated entities to rely more extensively in their plans and strategies on whichever measures best suit their particular circumstances will further improve cost effectiveness. The analysis the EPA performed to assess the costs, benefits, and other impacts of the proposed goals reflects this compliance flexibility, along with transmission and pipeline capabilities and constraints, fuel market and electricity dispatch dynamics, and seasonal electricity load requirements. As described below in Section X, the results indicate that the proposed state goals (discussed in Section VII) are readily achievable with no adverse impacts on electricity system reliability, and that impacts on retail electricity prices are modest and fall within the range of price variability seen historically in response to changes in factors such as weather and fuel supply. Further, the costs tend to decline over time as states and regulated entities take advantage of the available flexibility and expand deployment of more cost-effective measures (notably demand-side energy efficiency). The EPA considers this analysis strong confirmation of the reasonableness of the costs of the measures in the four building blocks in combination as the best system of emission reduction.
In this section, we discuss additional reasons why the measures in building blocks 2, 3, and 4, individually and in combination, meet the requirements to be components of the BSER. In particular, we discuss why they meet the definition of a “system of emission reduction,” and we provide additional reasons why they are the “best” that is “adequately demonstrated.” The interconnected nature of the electric system is an important part of our reasoning.
For the convenience of the reader, it is useful to reiterate the key CAA section 111 requirements: Section 111(d)(1) requires that each state's plan “establish[] standards of performance for any existing source” for certain types of air pollutants; and section 111(a)(1) defines a “standard of performance” as “a standard for emissions . . . which reflects the degree of emission limitation achievable through the application of the best system of emission reduction . . . adequately demonstrated.” These provisions require that, in this rulemaking, the affected sources must be subject to emissions standards, but the basis for those standards—the “system of emission reduction”—may be any method that reduces the affected sources' emissions, as long as that method is a “system” that meets the criteria for being the “best” that is “adequately demonstrated.”
As discussed in the Legal Memorandum, the EPA is justified in adopting this interpretation under the first step of the framework for administrative agencies to construe statutes that the U.S. Supreme Court established in
Specifically, the term “system,” which is not defined in the CAA, is broad: “A set of things working together as parts of a mechanism or interconnecting network.”
Even if these CAA provisions leave room for interpretation as to whether those measures must be considered components of such a system, the EPA's interpretation that they do is reasonable. As discussed in the Legal Memorandum, the EPA is justified in adopting this interpretation under the second step of the
As described earlier with respect to the individual building blocks, the measures in each of building blocks 2, 3, and 4 meet the criteria for the “best” system of emission reduction, and, generally for the same reasons, the three in combination do as well.
In addition, the measures in building blocks 2, 3, and 4, individually and in combination, are “adequately demonstrated.” As discussed earlier, thanks to the integrated nature of the electricity system, they have long been relied on to reduce costs in general, assure reliability, and implement pre-existing pollution control requirements in the least-cost manner. As also noted elsewhere in the preamble, and discussed in more detail in the following subsections, some utilities, states and regions are already relying on these measures for the specific purpose of reducing CO
Measures in building blocks 2, 3, and 4 may be undertaken or invested in by the affected EGUs themselves, which supports that these measures are “adequately demonstrated.” More specifically, the EPA believes that owners of units operating across a wide range of corporate, institutional and market structures (e.g., vertically integrated utilities in regulated markets, independent power producers, municipal utilities, and rural cooperatives) can take advantage of a broad range of reduction opportunities included in the building blocks. Because of the proposed lengthy planning period, owners can consider longer-term options such as implementing energy efficiency programs or replacement of older generating resources with more modern types of generation, as well as shorter-term options such as heat rate improvements and re-dispatch. Many companies, for example, already factor a carbon cost adder into their long-term planning decisions.
Large vertically integrated utilities generally have options within all four building blocks. They tend to have large and, as a general matter, at least somewhat diverse generation fleets. For their higher-emitting units, they have opportunities to use measures that reduce the units' CO
Municipal utilities and rural cooperatives that own generating asset portfolios also have multiple options for reducing CO
Some stakeholders have expressed concerns that municipal utilities and rural cooperatives can face other challenges as well. According to these stakeholders, in deregulated areas, even though these utilities may be fully vertically integrated entities, they may not have as much flexibility to control dispatch because they are operating in a competitive market, where they can be in a position in which they need to operate if called upon. Even in this case, the timing flexibility of the rule allows them to consider longer-term capacity planning strategies. These can include building or contracting for electric supply from lower-emitting sources, use of distributed renewable technologies, and use of demand-side energy efficiency measures. There are a number of municipal utilities and rural cooperatives that are already aggressively pursuing such strategies.
Independent power producers (IPPs) may also face unique challenges but nevertheless have options. Companies with coal-fired EGUs can implement efficiency improvements as well as other unit-level compliance options such as co-firing or fuel switching. While these types of companies do not use the integrated resource planning process that many vertically integrated utilities use, they still undertake long-term business planning and as a result are in a position to consider different long-term strategies related to their generating assets. Many IPPs are actively developing renewable generating capacity and natural gas-fired generating capacity. IPP owners could also fund demand-side energy efficiency programs and document the resulting electricity savings.
Another reason why the measures in building blocks 2, 3, and 4 are “adequately demonstrated” is that states may adopt them and, in fact, many states have already adopted many of them.
For example, several states have already adopted renewable energy (RE) and demand-side energy efficiency (EE) measures in their CAA section 110 state implementation plans (SIPs) for attaining and maintaining the national ambient air quality standards (NAAQS). The EPA has provided initial guidance for states to do so.
It should be recognized that each state's electric utility sector operates under distinctive conditions and circumstances. The EPA's proposal ensures that states retain flexibility to craft standards of performance that can accommodate characteristics including fuel sources, types of EGU owners within a state (e.g., investor-owned, municipal, and cooperative utilities, and independent power producers), and regulatory structure (e.g., regulated or restructured). States can tailor their regulatory mechanisms to recognize differences, for example by creating budgets on a company-wide basis or using market-based mechanisms such as mass-based trading systems, to ensure that requirements are achievable.
The proposal also recognizes that states have different resource bases and energy policies in place, and these differences are taken into account in the state goal-setting and computation process. For instance, while the EPA's BSER assumptions consider re-dispatch to NGCC units, they do not consider re-dispatch beyond the NGCC capacity already existing in a state. In that way, the proposal does not presume that
Furthermore, while the BSER reflects best practices for both renewables and energy efficiency, it also recognizes that some states have made more progress than others in these areas. The BSER allows time for states to ramp up to greater levels of energy efficiency and use and development of renewable energy resources, should they choose those approaches. With respect to renewable energy, the proposal also recognizes that different areas of the country have different resource bases and does not presume that a uniform level of penetration of renewable generation is appropriate for every state.
The features provided in this proposal to ensure policy flexibility can be used by all states to address their unique circumstances. In a regulated state, if a company's compliance strategies included reducing generation at higher-emitting EGUs, it would work through its state's integrated planning process to ensure that adequate generation was available through a combination of all four building blocks. Cost recovery, and cost oversight, can be achieved through rate cases before state regulators. In a restructured state, even if affected companies responded to the guidelines by reducing generation without themselves replacing that generation, the electricity markets that have developed would react to ensure the availability of replacement generation. Other companies would see opportunities to build or ramp up existing lower-emitting generation, and in some markets that treat demand-side resources on par with supply side resources, energy service companies would likely see opportunities. Further, state regulators can continue to play an important role in restructured states as well, authorizing or reviewing both renewable energy procurement and demand-side energy efficiency programs. In all types of market structures, large energy users might independently see additional energy efficiency opportunities or opportunities for self-generation using options such as combined heat and power, solar, or power purchase agreements, and states can structure their plans to allow the CO
Moreover, there are mechanisms through which states could require measures from any of the building blocks in state plans. In fact, the state plan formulation process through which CAA section 111(d) is implemented reinforces the determination that these measures are components of the BSER. For example, states would have authority to impose measures such as best practices for operation and maintenance of EGUs, dispatch limits, renewable energy resource requirements, and demand-side energy efficiency requirements. States also would have authority to establish requirements that change the relative costs of generation from more carbon-intensive and less carbon-intensive EGUs, for example by creating emission allowance systems that cause market participants and system operators to take account of CO
It also should be noted that during the public outreach sessions, stakeholders generally recommended that state plans be authorized to rely on, and that affected sources be authorized to implement, re-dispatch, renewable energy measures, and demand-side energy efficiency measures in order to meet states' and sources' emission reduction obligations. The EPA agrees that state plans may include these measures, at least under certain circumstances, as discussed in Section VIII, and that sources may rely on them to achieve required reductions. It is clear that these types of measures are well-accepted by the stakeholders as means to reduce emissions from affected sources. The fact that state plans and sources would be expected to use these types of measures to reduce emissions supports the view that these measures are part of a “system of emission reduction” for those sources that the EPA may evaluate against the appropriate criteria to determine whether they comprise the “best system of emission reduction . . . adequately demonstrated.”
Another reason why the measures in building blocks 2, 3, and 4 are “adequately demonstrated” is that they can be accommodated through the existing regional components of the electricity system.
On the regional level, ISO/RTOs control dispatch and are responsible for reliable operation of the bulk power system.
We note that some stakeholders have argued that CAA section 111(a)(1) does not authorize the EPA to identify re-dispatch, low- or zero-emitting generation, or demand-side energy efficiency measures (building blocks 2, 3, and 4) as components of the “best system of emission reduction . . . adequately demonstrated.” According to these stakeholders, as a legal matter, the BSER is limited to measures that may be undertaken at the affected units, and not measures that are beyond the affected units; the measures in building blocks 2, 3, and 4 are “beyond-the-unit” or “beyond-the-fenceline” measures because they are implemented outside of the affected units and outside their control; and as a result, those measures cannot be considered components of the BSER.
We welcome comment on this issue. As discussed above, we propose that the
There is an argument that the at-the-unit/beyond-the-unit distinction is not a meaningful one. Specifically, it could be argued that the distinction between at-the-unit and beyond-the-unit measures is largely artificial, because all of the emission reductions under consideration—whether from at-the-unit measures (e.g., fuel-switching or efficiency upgrades) or from beyond-the-unit measures—are, in fact, emission reductions at or from electric generating units on the interconnected electric grid. For example, neither the addition of renewable generation nor the reduction of end-user demand directly reduces atmospheric emission of CO
Nordhaus R., Gutherz I., “Regulation of CO
As an alternative to the approach described above for determining the “best system of emission reduction . . . adequately demonstrated,” the “system of emission reduction” may be identified as including, in addition to building block 1, the reduction of affected fossil fuel-fired EGUs' mass emissions achievable through reductions in generation of specified amounts from those EGUs. Under this approach, the measures in building blocks 2, 3, and 4 would not be components of the system of emission reduction but instead would serve as bases for quantifying the reduced generation (and therefore emissions) at affected EGUs, and assuring that the amount of reduced generation meets the criteria for the “best” system that is “adequately demonstrated” because, among other things, the reduced generation can be achieved while the demand for electricity services can continue to be met in a reliable and affordable manner. Specifically, the amount of generation from the increased utilization of NGCC units would determine a portion of the amount of the generation reduction component of the BSER for affected fossil fuel-fired steam EGUs, and the amount of generation from the use of expanded low- and zero-carbon generating capacity that could be provided, along with the amount of generation from fossil fuel-fired EGUs that could be avoided through the promotion of demand-side energy efficiency, would determine a portion of the amount of the generation reduction component of the BSER for all affected EGUs.
Reduced generation is encompassed by the terms of the phrase “system of emission reduction” in CAA section 111(a)(1), as a matter of
Reduction of, or limitation on, the amount of generation is already a well-established means of reducing emissions of pollutants in the electric sector, notwithstanding the fact that as a practical matter, some facilities may have to operate, or remain available, to ensure system reliability. For example, reduced generation by higher-emitting sources is one of the compliance options available to, and used by, EGUs to comply with the Clean Air Act acid rain program in CAA title IV, as well as the transport rules that we refer to as the NO
Reduced generation in specified amounts is part of the “best” system of emission reduction that is “adequately demonstrated.” Reduced generation is technically feasible because of a source's ability to limit its own operations. In addition, the amounts of generation and emission reductions may be determined with precision through the application of building block 2, 3, and 4 measures for increased generation from low- or zero-emitting sources and increased demand-side energy efficiency, which, in turn, ensure the reliability of the electricity grid and the affordability of electricity to businesses and consumers.
Because of the availability of the measures in building blocks 2, 3, and 4, the proposed levels of reduced generation are of reasonable cost for the affected source category and the nationwide electricity system, do not jeopardize reliability, result in an important amount of emission reductions, are consistent with current trends in the electricity sector, and promote the development and implementation of technology that is important for continued emissions reductions. All these results come about because the operation of the electrical
Reduced generation in those amounts is also “adequately demonstrated.” As noted above, the measures in building blocks 2, 3, and 4 are already in widespread use in the industry. At the levels proposed, they have the technical capability to substitute for reduced generation at some or all affected EGUs at reasonable cost. The NGCC capacity necessary to accomplish the levels of generation reduction proposed for building block 2 is already in operation or under construction. Moreover, it is reasonable to expect that the incremental resources reflected in building blocks 3 and 4 will develop at the levels requisite to ensure an adequate and reliable supply of electricity at the same time that affected EGUs may choose or be required to reduce their CO
Most broadly, with respect to the measures in building blocks 2, 3, and 4, provided there is sufficient lead time for planning, mechanisms are in place in both regulated and deregulated electricity markets to assure that substitute generation will become available and/or steps to reduce demand will be taken to compensate for reduced generation by affected EGUs. These mechanisms are based on, among other things, the integrated nature of the electricity system coupled with the availability of capacity in existing NGCC units, the growing institutional capacity of entities that develop renewable energy and demand-side energy efficiency resources, and the ability of system operators and state regulators to incentivize further development of those resources.
The EPA solicits comment on whether measures in addition to those in building blocks 2, 3, and 4 could support the showing that reduced utilization is “adequately demonstrated,” including additional NGCC capacity that may be built in the future, as discussed in Section VI.C.5.c above.
As discussed above, each of the approaches to determining the “best system of emission reduction . . . adequately demonstrated” entails applying the criteria described in the D.C. Circuit case law for evaluating the BSER. It should be emphasized that under the case law, the EPA has significant discretion in weighing the different criteria, and may weigh them differently in different rulemakings.
For the present proposal, the EPA is heavily weighting three criteria in particular: The amount of emission reductions, the cost of achieving those reductions, and the promotion of technology implementation—while also noting that the proposed BSER determination readily meets the other criteria as well. The EPA considers it especially important in this rulemaking, while ensuring that electricity system reliability is preserved and that costs are not unreasonable, to achieve a significant amount of emissions reductions in response to the urgency and the magnitude of the need to mitigate climate change. The EPA discusses this above in the sections concerning the scientific background for this rulemaking. The EPA also considers it especially important for the present proposal that the overall costs of achieving the emission reductions should be reasonable. Costs can be minimized through the flexibility to choose from a broad range of CO
In addition, in this rulemaking, the EPA is determining the BSER in a manner that is consistent with, and that provides further impetus for, current trends in the nation's electricity system that offer promise to reduce the carbon intensity of the system over the near- and long-term, while maintaining reliability and affordability. This approach is consistent with the case law, which authorizes the EPA to determine BSER by “balanc[ing] long-term national and regional impacts,” and by “using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems. . . .”
An important aspect of the BSER for affected EGUs is that the EPA is proposing to apply it on a statewide basis. The statewide approach also underlies the required emission performance level, which is based on the application of the BSER to a state's affected EGUs, and which the suite of measures in the state plan, including the emission standards for the affected
This state-wide approach both harnesses the efficiencies of emission reduction opportunities in the interconnected electricity system and is fully consistent with the principles of federalism that underlie the Clean Air Act generally and CAA section 111(d) particularly. That is, this provision achieves the emission performance requirements through the vehicle of a state plan, and provides each state significant flexibility to take local circumstances and state policy goals into account in determining how to reduce emissions from its affected sources, as long as the plan meets minimum federal requirements.
In this subsection, we describe how this approach, and the standards of performance for the affected EGUs that the states will establish through the process we describe, are consistent with the CAA section 111(d)(1) and (a)(1) provisions.
For convenience, we set out the requirements of CAA section 111(d)(1) and (a)(1) here: Under CAA section 111(d)(1), the state must adopt a plan that “establishes standards of performance for any existing source.” Under CAA section 111(a)(1), a “standard of performance” is a “standard for emissions . . . which reflects the degree of emission limitation achievable through the application of the best system of emission reduction . . . adequately demonstrated.” The EPA proposes to interpret these provisions as set forth in this sub-section.
The first step is for the EPA to determine the “best system of emission reduction . . . adequately demonstrated.” As discussed at length elsewhere, the EPA is proposing two alternative BSER. The first is the measures in building blocks 1 through 4 combined. This includes operational improvements and equipment upgrades that the coal-fired steam EGUs in the state may undertake to improve their heat rate by, on average, six percent and increases in, or retention of, zero- or low-emitting generation, as well as measures to reduce demand for generation, all of which, taken together, displace, or avoid the need for, generation from the affected EGUs. This BSER is a set of measures that impacts affected EGUs as a group. The alternative approach to BSER is building block 1 combined with reduced utilization from the affected EGUs in the state as a group, in the amounts that can be replaced by an increase in, or retention of, zero- or low-emitting generation, as well as reduced demand for generation.
After determining the BSER, the EPA then applies the BSER to each state's affected EGUs, on a state-wide basis. Building block 1 is applied to the coal-fired steam EGUs on a statewide basis; building block 2 is applied to increase the generation of the NGCC units in the state up to certain amounts, and decrease the amount of generation from steam EGUs accordingly; and the measures in building blocks 3 and 4 are applied to reduce, or avoid, generation from all affected EGUs on a state-wide basis. Under the alternative formulation of the BSER, the total amount of reduced generation from the affected EGUs in the state, associated with the measures in building blocks 2, 3, and 4, is determined on the basis of each state's affected EGUs as a group.
This statewide approach to applying the BSER is consistent with the CAA section 111(a)(1) definition of “standard of performance,” which, as quoted above, refers to “the application of the [BSER],” for the purpose of determining “the degree of emission limitation achievable,” but does not otherwise constrain how the BSER is to be applied.
As a result, the EPA may apply the BSER to all of the affected EGUs in the state as a group. Similarly, the implementing regulations give the EPA broad discretion to identify the group of sources to which the BSER is applied. The regulations provide that the EPA “will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate.” Applying the BSER to the affected EGUs in each state as a group is appropriate, and therefore is consistent with these regulations.
As part of applying the BSER, the EPA, to return to provisions of CAA section 111(a)(1), calculates the “emission limitation achievable through the application of the [BSER].” In this rulemaking, we refer to this amount as the state goal. As noted, the EPA expresses the state goal in the emission guidelines as an emission rate.
The state must develop a state plan that achieves the state goal, either in the form of an emission rate, as specified for the state in the emission guidelines, or a translated mass-based version of the rate-based goal. We refer to the state goal, in the form used by the state as the foundation of its plan, as the required emission performance level.
As part of its state plan, the state must establish “standards of performance” for its affected EGUs. To do so, the state may consider the measures the EPA identified as part of the BSER or other measures that reduce emissions from the affected EGUs. Moreover, the state has the flexibility to establish emission standards in the degree of stringency that the state considers appropriate. The primary limitation on the state's flexibility is that the emission standards applied to all of the state's affected EGUs—and, in the case of states that adopt the portfolio approach, the requirements imposed on other affected entities—taken as a whole, must be demonstrated to achieve the required emission performance level. In addition, the state may make the emission standards for any of its affected EGUs sufficiently stringent, so that the standards and any requirements imposed on other affected entities (if relevant), taken as a whole, achieve a level of emission performance that is better than the required emission performance level.
Under these circumstances—that the emission standards that the state establishes for its affected EGUs and any other requirements for the other affected entities, as relevant, taken together, are at least as stringent as necessary to achieve the required emission performance level for the state's affected EGUs—each emission standard that the state adopts for each of its affected EGUs will meet the definition of a “standard of performance” under CAA section 111(a)(1). Specifically, the “standard of performance” for each source will constitute, to return to the provisions of CAA section 111(a)(1), “a standard for emissions which reflects [that is, embodies, or represents]
These proposed interpretations of the provisions of CAA sections 111(d)(1) and (a)(1) are fully consistent with the EPA's overall approach in this rulemaking to determining and applying the BSER and identifying the appropriate level of emission performance for the affected EGUs. As noted, this approach entails applying the BSER on a state-wide basis and, based on the BSER, identifying the emission performance level for each state's affected EGUs that each state must achieve, so that each state may then assign the emission limitation obligations among its sources. As noted, this approach is fully consistent with the interconnected nature of the electricity system and with the principles of federalism that underlie CAA section 111(d).
It should be emphasized that each state has many options for assigning the emission limitation obligations among its affected sources. For example, the state could impose emission standards that are consistent with the BSER. Under these circumstances, the state may assign to different affected sources emission standards with different levels of stringency because the state will have determined that those standards are consistent with the nature of each source's participation in the state's electricity system. In addition, the state could authorize emission trading as part of the emission standards for affected sources. Under these circumstances, if an affected source's emission level was higher than the standard the state established for it, the source could achieve the standard by purchasing additional emission rights through the trading program.
Finally, it should be noted that states retain authority under CAA section 116 and 40 CFR 60.24(g) to impose standards of performance that, cumulatively, are more stringent than the emission performance level.
As discussed above, the EPA is soliciting comment on combining the category of steam EGUs and the category of combustion turbines (which include NGCC units) into a single category for fossil fuel-fired EGUs, for purposes of promulgating emission guidelines for CO
We consider our proposed findings of the BSER with respect to the various building blocks to be severable, such that in the event a court were to invalidate our finding with respect to any particular building block, we would find that the BSER consists of the remaining building blocks. The state goals that would result from any combination of the building blocks can be computed from data included in the Goal Computation TSD and its appendices using the methodology described in the preamble and that TSD.
We invite comment on all aspects of our proposed interpretation and alternate interpretation of the BSER for CO
In this section, the EPA sets out proposed state-specific CO
The proposed goals are expressed in the form of state-specific, adjusted
The EPA is also proposing that measures taken by a state or its sources
The EPA is proposing to finalize the goal for each state as proposed, and adjusted as may be appropriate based on comments. A state may demonstrate during the comment period that application of one of the building blocks to that state would not be expected to produce the level of emission reduction quantified by the EPA because implementation of the building block at the levels envisioned by the EPA was technically infeasible, or because the costs of doing so were significantly higher than projected by the EPA. While the EPA would consider this in setting final state goals, the EPA would also consider (and would expect commenters to address) whether a similar overall state goal could still be achieved through more aggressive implementation of one or more of the measures encompassed in the other building blocks or through other, comparable measures. For example, if a state demonstrates during the public comment period that the state's coal-fired steam EGUs could only achieve an average four percent heat rate improvement, instead of the six percent that the EPA is proposing to determine is achievable from application of building block 1, the EPA would not adjust the state's goal to reflect that change unless the state also demonstrates that it could not get additional reductions from application of building blocks 2, 3 or 4, or in related, comparable measures.
Each of the building blocks establishes a reasonable level of reductions, but not necessarily the maximum amount that could be achieved if that building block, and no other, were the basis supporting the BSER. Together the building blocks establish a reasonable overall level of reductions and effort that the EPA considers appropriate at this time. This amount of emission reductions is significant and will require effort and adjustments throughout the electricity sector. In light of the overall effort to achieve the state goals based on a combination of all four building blocks at the levels specified, the EPA is not proposing a higher level of reductions at this time, even though the measures in the building blocks could be implemented more stringently to achieve greater emission reductions.
Because the building blocks each establish a reasonable level of emission reduction rather than the maximum possible level of reduction, the EPA expects that, for any particular state, even if the application of the measures in one building block to that state would not produce the level of emission reductions reflected in the EPA's quantification for that state, the state will be able to reasonably implement measures in other of the building blocks more stringently, so that the state would still be able to achieve the proposed goal. Accordingly, the EPA proposes that even if a state demonstrates during the comment period that application of a building block to that state would not result in the level of emission reductions reflected in the EPA's quantification for that state, then the state should also explain why the application of the other building blocks would not result in greater emission reductions than are reflected in the EPA's quantification for that state. In light of the fact that the building blocks are based on a reasonable level of stringency and not the most stringent possible level, the EPA expects that such offsetting emission reductions at the state's affected EGUs from the application of other building blocks will be available, so that the EPA will be able to finalize the state goals as proposed. For example, a state's inability to meet the level of emission reductions anticipated through use of one building block may free up resources that the state could then devote to more stringent implementation of another building block. This approach would mean that overall, the same nationwide level of emission reductions as proposed would be achieved. The EPA invites comment on this aspect of the proposal.
At this time, the EPA is not proposing CO
Issues related to the establishment of CO
With respect to territories, the EPA is currently aware of potentially affected EGUs in Puerto Rico, the U.S. Virgin Islands, and Guam. The EPA requests comment on how the BSER would apply to these territories, as well as to American Samoa or the Northern Mariana Islands if potentially affected EGUs are subsequently identified in those territories. In particular, the EPA solicits comment on appropriate alternatives for territories that do not have access to natural gas.
The remainder of this section addresses five sets of topics. First, we discuss several issues related to the form of the goals. Second, we describe the proposed state goals and the computation procedure. Third, we discuss several types of state flexibility with respect to the goals. Fourth, we describe the alternate set of goals offered for comment and certain other approaches we considered. Finally, we discuss the proposal's compatibility with the need to ensure a reliable, affordable supply of electricity.
Some of the topics addressed in this section are addressed in greater detail in supplemental documents available in the docket for this rulemaking, including the Goal Computation TSD and the Greenhouse Gas Abatement Measures TSD. Specific topics addressed in the various TSDs are noted throughout the discussion below.
The proposed goals are presented in the form of adjusted output-weighted-average CO
First, the EPA proposes to use an emission rate-based form for the state-specific goals included in the guidelines, and to give each state the opportunity to translate its rate-based goal to an equivalent mass-based form for state plan purposes. Each of the two forms of goals presents advantages, and states have expressed support for having the flexibility to use either form. Defining emission performance levels in a rate-based form provides flexibility to accommodate changes in the overall quantities of electricity generated in response to increases in electricity demand. Defining emission performance levels in a mass-based form provides relative certainty as to the absolute emission levels that would be achieved as well as relative simplicity in accommodating and accounting for the emission impacts of a wide variety of emission reduction strategies. In light of these respective advantages, we propose to set an emission rate-based form of goal, and to allow any state to translate the rate-based goal to an equivalent mass-based emission performance level for state plan purposes. This approach allows each state to maximize the advantages it considers optimal and is consistent with the state flexibility principle that is central to the EPA's development of this program.
The second aspect noted above concerns the proposed choice of state-specific output-weighted-average emission rates for all affected EGUs in each state rather than nationally uniform emission rates for particular types of affected EGUs. Here, the EPA's main consideration has been to ensure that the proposed goals reflect opportunities to manage CO
The third aspect noted above regarding the proposed form of the goals concerns the adjustments made to the output-weighted-average emission rates in order to accommodate reduced utilization of affected EGUs associated with measures such as increases in low- and zero-carbon generating capacity and demand-side energy efficiency. We recognize that these measures support reduced overall CO
The fourth aspect noted above concerns the proposed expression of the goals in terms of net energy output
The final aspect noted above has to do with the severability of the four building blocks, discussed in Section VI above, upon which the goals are based. Because the building blocks can be implemented independently of one another and the goals are the sum of the emission reductions from all of the building blocks, if any of the building blocks is found to be an invalid basis for the “best system of emission reduction . . . adequately demonstrated,” the goals would be adjusted to reflect the emissions reductions from the remaining building blocks. As noted above, the state goals that would result from any combination of the building blocks can be computed from data included in the Goal Computation TSD and its appendices using the methodology described below and in that TSD.
We invite comment on all aspects of the proposed form of the goals.
The EPA has developed proposed goals for state plans reflecting application of the BSER, based on all four building blocks described earlier, to pertinent data for each state. The goals are intended to represent CO
The proposed goals are expressed as adjusted output-weighted-average emission rates for all affected EGUs in a state. As discussed earlier in this section, a goal expressed as an unadjusted output-weighted-average emission rate would fail to account for mass emission reductions from reductions in the total quantity of fossil fuel-fired generation associated with state plan measures that increase low- or zero-carbon generating capacity or demand-side energy efficiency. Accordingly, under the proposed goals, the emission rate computation includes an adjustment designed to reflect those mass emission reductions. The adjustment is made by estimating the annual net generation associated with an achievable amount of qualifying new low-carbon and zero-carbon generating capacity, as well as the annual avoided generation associated with an achievable portfolio of demand-side energy efficiency measures, and adding those MWh amounts to the energy output from affected units that would have been used in an unadjusted output-weighted-average emission rate computation.
The methodology used to compute each state's proposed goal is summarized on a step-by-step basis below. The methodology is described in more detail in the Goal Computation TSD, which includes a numerical example illustrating the full procedure. The development of the data inputs used in the computation procedure is discussed in Section VI above and in the Greenhouse Gas Abatement Measures TSD.
Step 1 (compilation of baseline data). On a state-by-state basis, we obtained total annual quantities of CO
Step 2 (application of building block 1). The total CO
Step 3 (application of building block 2). If the generation data for the NGCC group in a state developed in Step 1 showed average annual utilization below 70 percent of those units' maximum possible output, and the generation data developed in Step 1 also included generation from the coal-fired steam or oil/gas-fired steam EGU groups in that state, the generation and emissions figures for the NGCC group were increased, and the generation and emissions figures for the coal-fired and oil/gas-fired steam EGU groups from Step 2 were proportionately
Step 4 (application of building block 3). We estimated the total quantities of generation from renewable generating capacity and from under-construction or preserved nuclear capacity for each state using the approaches described in Section VI.C.3 above. Separate estimates of renewable generation were computed for each year of the plan period for each state based on the state's 2012 renewable generation and a regional growth factor. Nuclear generation was estimated as the amount of under-construction and preserved nuclear capacity for each state operated at a utilization rate of 90 percent, consistent with recent industry-wide average utilization rates for nuclear units.
Step 5 (application of building block 4). We estimated the total MWh amount by which generation from each state's affected EGUs would be cumulatively reduced in each year of the plan period associated with implementation in that state of demand-side energy efficiency programs resulting in annual incremental reductions in the state's electricity usage (relative to usage absent those programs) of 1.5 percent each year, as described in Section VI.C.4 above. Separate estimates were developed for each year to reflect the fact that energy efficiency programs that are implemented on an ongoing basis would be expected to produce larger cumulative impacts on total annual electricity usage over time. For states that are net importers of electricity, the estimated reduction in the generation by the state's affected EGUs was scaled down to reflect an expectation that a portion of the generation avoided by the demand-side energy efficiency would occur at EGUs in other states.
Step 6 (computation of annual rates). We computed adjusted output-weighted-average CO
[(Coal gen. × Coal emission rate) + (OG gen. × OG emission rate) + (NGCC gen. × NGCC emission rate) + “Other” emissions]/[Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. + RE gen. + EE gen.]
This formula and its elements are further explained in the Goal Computation TSD, as well as in the text above.
Step 7 (computation of interim and final goals). The final 2030 goal for each state is the annual rate computed for 2029 for the state from Step 6 above. We computed the 2020-2029 interim goal for each state as the simple average of the annual rates computed for each of the years from 2020 to 2029 for the state from Step 6 above.
It bears emphasis that the procedure described above is proposed to be used only to determine state goals, and the particular data inputs used in the procedure are not intended to represent specific requirements that would apply to any individual EGU or to the collection of EGUs in any state. The specific requirements applicable to individual EGUs, to the EGUs in a given state collectively, or to other affected entities in the state, would be based on the standards of performance established through that state's plan. The details of how states could attain emission performance levels consistent with the goals through different state plan approaches that recognize emission reductions achieved through all the building blocks are discussed further in Section VIII on state plans.
We invite comment on all aspects of the goal computation procedure. (Note that we also invite comment on certain specific alternate data inputs to the procedure in Section VI.C above.) We also specifically invite comment on the state-specific historical data to which
With respect to building block 2, we specifically request comment on the following alternate procedure: In Step 3, to the extent that generation from a state's NGCC group was increased consistent with the NGCC utilization rate target, in order to maximize the resulting emission reductions, we would decrease generation from the state's coal-fired steam group first, and then decrease generation from the state's oil/gas-fired steam group (instead of decreasing generation from the coal-fired steam and oil/gas-fired steam groups proportionately).
With respect to building block 4, we specifically invite comment on the alternative in Step 5 of scaling up the estimated reduction in the generation by affected EGUs in net electricity-exporting states to reflect an expectation that a portion of the generation avoided in conjunction with the demand-side energy efficiency efforts of other, net electricity-importing states would occur at those EGUs, analogous to the proposed adjustment for net electricity-importing states described in Step 5. We also request comment on the alternative of making no adjustment in Step 5 for either net electricity-importing or net electricity-exporting states. These alternatives are discussed in the Goal Computation TSD.
We also request comment on whether CO
As promulgated in the final rule following consideration of comment, the state-specific goals will be binding emission guidelines. States' ability to achieve emission performance levels consistent with the binding goals is enhanced by several distinct types of flexibility: (i) Choices as to the measures employed, including the timing of their implementation; (ii) the ability to translate from a rate-based form of goal to a mass-based form of goal; and (iii) the opportunity to pursue multi-state plan approaches.
First, a core flexibility provided under CAA section 111(d) is that while states are required to establish standards of performance that reflect the degree of emission limitation from application of the control measures that the EPA identifies as the BSER, they need not mandate the particular control measures the EPA identifies as the basis for its BSER determination. In developing the building block data inputs applied to each state's historical data to develop the goals, the EPA targeted reasonably achievable rather than maximum performance levels. The overall goals therefore represent reasonably achievable emission performance levels that provide states with flexibility to pursue some building blocks more extensively and others less extensively than the degree reflected in the EPA's data inputs while meeting the overall goals. States can also choose to include in their plans other measures that reduce CO
Further, by allowing states to demonstrate emission performance by affected EGUs on an average basis over a multi-year interim plan period of as long as ten years, the EPA's proposed approach increases states' flexibility to choose among alternative potential plan measures. For example, by taking advantage of the multi-year flexibility, a state could choose to rely more heavily in its plan on measures whose effectiveness tends to grow over time, such as demand-side energy efficiency programs. This flexibility could also help states address concerns about stranded assets, for example, by enabling states to defer imposition of requirements on EGUs that may be scheduled to retire after 2020 but before 2029.
The second type of flexibility noted above is that while the EPA is proposing to establish goals in an emission rate-based form, we are also proposing to provide states with the flexibility to translate the rate-based goals to mass-based goals in order to accommodate states' potential interest in having emission performance requirements measured in absolute tons. For example, the northeastern and Mid-Atlantic states that currently participate in the mass-based Regional Greenhouse Gas Initiative (RGGI) may choose to develop state plans (or a multi-state plan, as noted below) establishing mass-based emission performance levels designed to be met at least in part through standards of performance based on RGGI's existing market-based CO
Third, the EPA's approach allows states to submit multi-state plans. The EPA expects this flexibility to reduce the cost of achieving the state goals and therefore expects it to be attractive to states. For example, the RGGI-participating states could choose to submit a multi-state mass-based plan that demonstrates emission performance by affected EGUs on a multi-state basis. Additional states may also choose to join a multi-state plan. The mechanics of translating rate-based goals into mass-based goals and considerations related to multi-state plans are discussed below in Section VIII on state plans.
Some stakeholders have suggested that states themselves should be allowed to quantify the level of emission reduction resulting from the application of BSER or, if the EPA establishes goals, the states should be allowed to adjust the goals or to treat the goals established by the EPA as advisory rather than binding. Consistent with the existing implementing regulations for CAA section 111(d) at 40 CFR part 60, this quantification is the EPA's role.
By the same token, because the state goals are an integral part of the emission guidelines that the framework regulations authorize the EPA to establish, the goals are binding, and the states, in their CAA section 111(d) plans, must meet those goals and may not make them less stringent. This matter, too, is resolved by the implementing regulations.
In addition to the proposed state-specific emission rate-based goals described above, the EPA has developed for public comment an alternate set of goals reflecting less stringent application of the building blocks and a shorter implementation period. The alternate final goals represent emission performance that would be achievable by 2025, after a 2020-2024 phase-in period, with interim goals that would apply during the 2020-2024 period on a cumulative or average basis as states progress toward the final goals.
Because the time period for implementation relates directly to the emission reductions that are achievable and therefore what measures, and at what level of stringency, constitute the BSER, the alternate goals reflect several differences in data inputs from the proposed goals. Specifically, a value of four percent (instead of six percent) was used for the potential improvement in carbon intensity of coal-fired EGUs in Step 2; a value of 65 percent (instead of 70 percent) was used for the potential annual utilization rate of NGCC units in Step 3; and a value of one percent (instead of 1.5 percent) was used for the annual incremental electricity savings achievable through a portfolio of demand-side energy efficiency programs in Step 5. (No change was made to the data inputs regarding less carbon-intensive generating capacity in Step 4.) As noted above, the alternate goals also reflect a shortening of the proposed phase-in period from ten years (2020-2029) to five years (2020-2024) to reflect an expectation that less stringent goals could be achieved in less time. Steps 5, 6, and 7 of the goal computation procedure therefore were performed for the span of years from 2020 to 2024 rather than for the span from 2020 to 2029. The alternate goals are set forth in Table 9 below.
The EPA recognizes that its approach to the alternate goals, comprising less stringent requirements in each of the building blocks to be achieved over a shorter compliance horizon, follows the logic of including time as one of the functions of the BSER determination. At the same time, we also recognize that the components of the alternate goals may reflect an overly conservative approach. Specifically, the alternate goals as set forth above may underestimate the extent to which the key elements of the four building blocks—achieving heat rate improvements at EGUs, switching generation to NGCC facilities, fostering the penetration of renewable resources or improving year-to-year end-use energy efficiency—can be achieved rapidly while preserving reliability and remaining reasonable in cost. Accordingly, we request comment on the alternate goals, particularly with respect to whether any one or all of the building blocks in the alternate goals
It is worth noting that the EPA projects that the alternate goals will achieve emission reductions equal to 23 percent below 2005 level in 2025. The EPA's analysis shows that under the proposed goals described in Section VII.C above, power sector emissions will be 29 percent below 2005 levels in 2025, suggesting that the kinds of changes contemplated in the four building blocks, even as early as 2025, will be yielding reductions far greater than the 23 percent projected for the alternate goals as set forth above in this subsection.
The EPA has considered other approaches to setting goals. In particular, given the interconnected nature of the power sector and the importance of opportunities for shifting generation among EGUs, we considered whether goals should be set on a multi-state basis reflecting the scope of existing regional transmission control areas. We also considered whether goals should be set on a state-specific basis, but regional rather than state-specific evaluations should be used to assess the estimated opportunities to reduce utilization of the most carbon-intensive EGUs by shifting generation to less carbon-intensive EGUs. A potential advantage of using regional evaluations is the ability to recognize additional emission reduction opportunities that would be available at reasonable costs based on a more complete representation of the capabilities of existing infrastructure to accommodate shifts in generation among EGUs in multiple states. We request comment on whether, and if so how, the EPA should incorporate greater consideration of multi-state approaches into the goal-setting process, and on the issue of whether, and if so how, the potential cost savings associated with multi-state approaches should be considered in assessing the reasonableness of the costs of state-specific goals.
Many stakeholders raised concerns that this regulation could affect the reliability of the electric power system. The EPA agrees that reliability must be maintained and in designing this proposed rulemaking has paid careful attention to this issue. The EPA has met on several occasions with staff and managers from the Department of Energy and the Federal Energy Regulatory Commission to discuss our approach to the rule and its potential impact on the power system. EPA staff and managers have also had numerous discussions with state public utility commissioners and their staffs to get their suggestions and advice concerning this rule, including how to address reliability concerns.
In addition, the EPA met with independent system operators several times to discuss any potential impact of this rule on grid reliability. The ISO/RTO Council, a national organization of electric grid operators, offered analytic support to help states design programs that do not compromise the regional bulk power system. They also offered to help states develop regional approaches which may reduce costs and strengthen the reliability of the electricity grid. Specifically, the ISO/RTO Council has suggested that ISOs and RTOs could provide analytic support to help states develop and implement their plans. The ISOs and RTOs have the capability to model the system-wide effects of individual state plans. Providing assistance in this way, they felt, would allow states with borders that fall within an ISO or RTO footprint to assess the system-wide impacts of potential state plan approaches. In addition, as the state implements its plan, ISO/RTO analytic support would allow the state to monitor the effects of its plan on the regional electricity system. ISO/RTO analytic capability could help states assure that their plans are consistent with region-wide system reliability. The ISO/RTO Council suggested that the EPA ask states to consult with the applicable ISO/RTO in developing their state plans. The EPA agrees with this suggestion and encourages states with borders that fall within one or more ISO or RTO footprints to consult with the relevant ISOs/RTOs.
The EPA has met with the U.S. Department of Agriculture as well to discuss how we can address the concerns of small, relatively isolated power generators in rural America and especially the electric cooperatives. Many of these entities have special challenges, as they may have small, older carbon-intensive assets and might have particular challenges meeting carbon requirements.
With all of this in mind, the EPA in determining the BSER looked specifically at the reasonableness of the costs of control options in part to ensure that the options would not have a negative effect on system reliability. The BSER, including each of the building blocks, was determined to be feasible at reasonable costs over the timeframe proposed here. Further, under the Clean Air Act the states are given the flexibility to design state plans that include any measure or combination of measures to achieve the required emission limitations. States are not required to use each of the measures that the EPA determines constitute the BSER or use those measures to the same degree or extent that the EPA determines is feasible at a reasonable cost. Thus, each state has the flexibility to choose the most cost-effective measures given that state's energy profile and economy, as long as the state achieves the reductions necessary to meet its goal. Many market-based approaches which states may choose reduce the costs of compliance. They can allow certain units that are seldom used to remain in operation if they are needed for reliability purposes. Multi-state approaches also reduce costs and stress on the grid and so can help to reduce any concern about electricity reliability.
States may choose measures that would ease pressures on system reliability. This is true for many demand-side management approaches, including programs to encourage end-use energy efficiency, distributed generation, and combined heat and power, which actually reduce demand for centrally generated power and thus relieve pressure on the grid.
The EPA is proposing a 10-year period over which to achieve the full required CO
The EPA's supporting analysis for this rule includes an examination of the effects of the rule on regional resource adequacy.
The EPA concludes that the proposed rule will not raise significant concerns over regional resource adequacy or raise the potential for interregional grid problems. The EPA believes that any remaining local issues can be managed through standard reliability planning processes. The flexibility inherent in the rule is responsive to the CAA's recognition that state plans for emission reduction can, and must, be consistent with a vibrant and growing economy and reliable, affordable electricity to support that economy. The EPA welcomes comments and suggestions on this issue.
After the EPA establishes the state-specific rate-based CO
The state must then establish an emission standard or set of emission standards, and, perhaps other measures, along with implementing and enforcing measures, that will achieve a level of emission performance that is equal to or better than the level specified in the state plan.
The state must then adopt the state plan through certain procedures, which include a state hearing. Within the time period specified in the emission guidelines (from as early as June 30, 2016 to as late as June 30, 2018, depending on the state's circumstances), the state must submit its complete state plan to the EPA. The EPA then must determine whether to approve or disapprove the plan. If a state does not submit a plan, or if the EPA does not approve a state's plan, then the EPA must establish a plan for the state.
As discussed in Section V.D of this preamble, in the case of a tribe that has one or more affected EGUs located in its area of Indian country, if the EPA determines that a CAA section 111(d) plan is necessary or appropriate, the EPA has the responsibility to establish a CAA section 111(d) plan for that area of Indian country where affected sources are located unless the tribe on whose lands an affected source (or sources) is located seeks and obtains authority from the EPA to establish a plan itself, pursuant to the Tribal Authority Rule.
This section is organized into six parts. First, we discuss the types of plans that we propose states could submit. Second, we address timing for plan implementation and achievement of state emission performance goals for affected EGUs. Third, we discuss the proposed state plan approvability criteria. Fourth, we summarize the proposed components of an approvable state plan. Fifth, we address the proposed process and timing for submittal of state plans. Sixth, we identify several key considerations for states in developing and implementing plans, including: Affected entities with obligations under a plan; treatment of existing state programs; incorporation of renewable energy (RE) and demand-side energy efficiency (EE) programs in certain plans; quantification, monitoring, and verification of RE and demand-side EE measures; reporting and recordkeeping for affected entities; treatment of interstate effects; and projection of emission performance. Finally, we discuss a number of additional factors that could help states meet their CO
In this action, the EPA is proposing emission guidelines in the form of state-specific CO
The EPA recognizes that each state has different state policy considerations—including varying emission reduction opportunities and existing state programs and measures—and that the characteristics of the electricity system in each state (e.g., utility regulatory structure, generation mix, electricity demand) also differ. The agency also anticipates—and supports—states' commitments to a wide range of policy preferences that could encompass those of states like Kentucky, West Virginia and Wyoming seeking to continue to feature significant reliance on coal-based generation; states like Minnesota, Colorado, California and the nine RGGI states seeking to build on actions and policies they have already undertaken; and states like Washington and Oregon seeking to integrate sustainable forestry and renewable energy strategies. The proposed plan guidelines provide states with options for establishing emission standards in a manner that accommodates a diverse range of state approaches. Each state will have significant flexibility to determine how to best achieve its CO
The proposed plan guidelines would also allow states to collaborate and to develop plans that provide for demonstration of emission performance on a multi-state basis, in recognition of the fact that electricity is transmitted across state lines, and that state measures may impact, and may be explicitly designed to reduce, regional EGU CO
Although state CAA section 111(d) plans must assure that the emission performance level is achieved through
Three important issues in the design of state plans include: (1) Whether the plan should require the affected EGUs to be subject to emission limits that assure that the emission performance level is achieved, or instead, whether the plan could rely on measures, such as renewable energy (RE) or demand-side energy-efficiency (EE), to assure the achievement of part of the emission performance level; (2) whether the responsibility for all of the measures other than emission limits should fall on the affected EGUs, or, instead, could fall on entities other than affected EGUs; and (3) whether the fact that requiring all measures relied on to achieve the emission performance level to be included in the state plan renders those measures federally enforceable. These issues and the EPA's proposed approach are addressed in detail in the sections that follow.
The EPA is proposing that all measures relied on to achieve the emission performance level be included in the state plan, and that inclusion in the state plan renders those measures federally enforceable.
In light of current state programs, and of stakeholder expressions of concerns over the above-noted issues, including legal enforcement considerations, with respect to those programs, the EPA is proposing to authorize states either to submit plans that hold the affected EGUs fully and solely responsible for achieving the emission performance level, or to submit plans that rely in part on measures imposed on entities other than affected EGUs to achieve at least part of that level, as well as on measures imposed on affected EGUs to achieve the balance of that level. The EPA requests comment on this proposed approach, as opposed to the approach under which state plans simply would be required to hold the affected EGUs fully and solely responsible for achieving the emission performance level.
In addition, the EPA is soliciting comment on several other types of state plans that may assure the requisite level of emission performance without rendering certain types of measures federally enforceable and that limit the obligations of the affected EGUs.
In assessing the types of state plans to authorize, the EPA reviewed existing state programs that reduce CO
In addition, during the EPA's extensive outreach efforts, many stakeholders expressed concern over the extent of responsibility that fossil fuel-fired EGUs would be required to bear for the required emission reductions, in particular, those associated with RE and demand-side EE measures. These stakeholders recommended that the EPA authorize states to achieve emission reductions from RE and demand-side EE measures by imposing requirements on entities other than fossil fuel-fired EGUs, and without imposing legal responsibility for these emission reductions on those EGUs.
Accordingly, the EPA is proposing to authorize a state plan to adopt what we refer to as a “portfolio approach,” in which the plan would include emission limits for affected EGUs along with other enforceable measures, such as RE and demand-side EE measures, that reduce CO
In addition, a portfolio approach could either be what we refer to as “utility-driven” or “state-driven,” depending on the utility regulatory structure in a state. Under a utility-driven approach, a state plan may include, for example, measures implemented consistent with a utility integrated resource plan, including both measures that directly apply to affected EGUs (e.g., repowering or retirement of one or more EGUs) as well as RE and demand-side EE measures that avoid EGU CO
The EPA is proposing to authorize state plans to adopt the portfolio approach and is proposing to interpret the CAA as allowing that approach, as described in more detail below. CAA section 111(d)(1) would certainly allow state plans to require the affected EGUs to be the sole entities legally responsible for achieving the emission performance level. The EPA is also soliciting comment on whether it can reasonably interpret CAA section 111(d)(1) to allow states to adopt plans that require EGUs and other entities to be legally responsible for actions required under the plan that will, in aggregate, achieve the emission performance level.
We note that some existing state programs, such as RGGI in the northeastern states, do impose the ultimate responsibility on fossil fuel-fired EGUs to achieve the required emission reductions, but are also designed to work either concurrently, or in an integrated fashion, with RE and demand-side EE programs that reduce the cost of meeting those emission limitations. These existing programs offer a possible precedent for another type of CAA section 111(d) state plan. Such a plan approach could rely on CO
It should be noted that state plan approaches that impose legal responsibility on the affected EGUs to achieve the full level of required emission performance could incorporate RE and demand-side EE measures regardless of whether the emission standards that those plans apply to the affected EGUs take the form of an emission rate or a mass limit. Plans with rate-based emission limits could incorporate enforceable RE and demand-side EE measures by adjusting an EGU's CO
Another concern expressed by some stakeholders is that including RE and demand-side EE measures in state plans would render those measures federally enforceable and thereby extend federal presence into areas that, to date, largely have been the exclusive preserve of the state and, in particular, state public utility commissions and the electric utility companies they regulate. These stakeholders suggest that states could rely on RE and demand-side EE programs as complementary measures to reduce costs for, and otherwise facilitate, EGU emission limits without including those measures in the CAA section 111(d) state plan. Under this suggested approach, the EGU emission limits would be federally enforceable, but RE and demand-side EE measures would serve as complementary measures and would not be enforceable under federal law; instead, they would remain enforceable under state law. According to stakeholders, those types of state programs, particularly because they are well-established, can be expected to achieve their intended results. Thus, they suggest that the states could conclude that those RE and demand-side EE measures would be beneficial in assuring the achievement of the required emission performance level by the affected EGUs specified in the CAA section 111(d) state plan, even without including those measures in the plan.
As another vehicle for approving CAA section 111(d) plans for states that wish to rely on state RE and demand-side EE programs but do not wish to include those programs in their state plans, the EPA requests comment on what we refer to as a “state commitment approach.” This approach differs from the proposed portfolio approach, described above, in one major way: Under the state commitment approach, the state requirements for entities other than affected EGUs would not be components of the state plan and therefore would not be federally enforceable. Instead, the state plan would include an enforceable commitment by the state itself to implement state-enforceable (but not federally enforceable) measures that would achieve a specified portion of the required emission performance level on behalf of affected EGUs. The agency requests comment on the appropriateness of this approach. The agency also requests comment on the policy ramifications of the following: Under this approach, the state programs upon which the state bases its commitment may, in turn, rely on compliance by third parties, and if those state programs fail to achieve the expected emission reductions, the state could be subject to challenges—including by citizen groups—for violating CAA requirements and, as a result, could be held liable for CAA penalties.
We also solicit comment on a variation of this state commitment plan approach that is also designed to address stakeholder concerns, noted above, about imposing sole legal responsibility on affected EGUs for achieving the emission performance level. With this variation, the state plan would in effect shift a portion of that responsibility to the state, in the following manner: The state plan would impose the full responsibility for achieving the emission performance level on the affected EGUs, but the state would credit the EGUs with the amount of emission reductions expected to be achieved from, for example, RE or demand-side EE measures. The state would then assume responsibility for that credited amount of emission reductions in the same manner as the state commitment plan approach discussed above. We solicit comment on whether, if the EPA were to conclude that CAA section 111(d) requires state plans to include standards of performance applicable to affected EGUs that achieve the emission performance level, this type of state plan would meet that requirement while also assuring those EGUs an important measure of support.
The EPA is proposing to interpret the relevant provisions in CAA section 111 to authorize state plans that achieve emissions reductions from affected EGUs by means of the portfolio approach. CAA section 111(d)(1) requires each state to submit a plan that “(A) establishes standards of performance for any existing source [for certain air pollutants] . . . and (B) provides for the implementation and enforcement of such standards of performance.” CAA section 111(a)(1) defines a “standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction . . . adequately demonstrated.”
These provisions make clear that emission limits that are enforceable against affected EGUs appropriately belong in state plans because they clearly are “standards of performance.” However, the terms of CAA section 111(d)(1) do not explicitly address whether, in addition to emission limits on affected EGUs, state plans may include other measures for achieving the emission performance level. Nor do they address whether entities other than affected EGUs may be subject to requirements that contribute to reducing EGU emissions. Under the U.S. Supreme Court's 1984 decision in
The EPA is proposing to interpret the phrases “standards of performance for any existing source” and “the implementation and enforcement of such standards of performance” to encompass and allow the various components of the portfolio approach. To the extent that a portfolio approach contains measures that are not standards of performance or do not implement or enforce such standards, the EPA is proposing to interpret CAA section 111 as allowing state CAA section 111(d) plans to include measures that are neither standards of performance nor measures that implement or enforce those standards, provided that the measures reduce CO
The EPA's proposed interpretation is based, in part, on CAA section 111(d)'s requirement that states set performance standards “for” affected sources. Although “for” could be read as meaning that the standards must apply to affected sources, “for” is also reasonably interpreted to have a more capacious meaning: Standards (such as EE and RE standards) are reasonably considered to be “for” affected sources if they would have an effect on affected sources by, for example, causing reductions in affected EGUs' CO
The EPA also requests comment on another approach: Whether “standards of performance for [affected sources]” is reasonably read to include the emission performance level (i.e., the state goal) on grounds that the level is “a standard for emissions” because it is in the nature of a requirement that concerns emissions and it is “for” the affected sources because it helps determine their obligations under the plan.
Moreover, where the specific measures in the portfolio approach are not themselves a “standard of performance,” state plans may include measures that implement or enforce a standard of performance. For example, if the state's plan achieves the emission performance level through rate-based emission limits applicable to the affected sources, coupled with a crediting mechanism for RE and demand-side EE measures, we propose that RE and demand-side EE measures may be included in the plan as “implement[ing]” measures because they facilitate the sources' compliance with their standards of performance. We solicit comment on the extent to which measures such as RE and demand-side EE may be considered “implement[ing]” measures in state plans if they are not directly tied to emission reductions that affected sources are required to make through emission limits, and if they are requirements on entities other than the affected sources. In addition, the EPA proposes to interpret CAA section 111(d)(1) to allow state plans to include components of the portfolio approach that are measures that would reduce emissions from affected sources, even if those measures are neither “standards of performance for existing sources” nor measures “for the implementation and enforcement of such standards of performance.” There is no specific language in CAA section 111(d) or elsewhere in the Act that prohibits states from including measures other than performance standards and implementation and enforcement measures, provided that they reduce emissions from affected EGUs.
This interpretation is consistent with the principle of cooperative federalism, which is one of the foundational principles of the Clean Air Act and which supports providing flexibility to states to meet environmental goals (provided minimum CAA statutory requirements are met). This general principle, especially when combined with the statutory directive that CAA section 111(d) regulations shall establish procedures “similar to that provided by section 110,” supports an interpretation of CAA section 111(d) that allows states sufficient flexibility in meeting the state goal set under CAA section 111(d) to include in their CAA section 111(d) plans other measures (i.e., measures that are neither performance standards nor measures that enforce or implement performance standards). The EPA solicits comment on all aspects of its proposed interpretation that states have this flexibility in selecting measures for their state plans under CAA section 111(d).
An alternative interpretation of CAA section 111(d)(1) would suggest that the responsibility to achieve the state's required emission performance level must be assigned solely to affected EGUs. As described elsewhere in this preamble, there are a number of state-level CO
We request comment on all of the interpretations discussed in this section generally, and on all legal issues under CAA section 111(d)(1) with respect to what measures can be included in a state plan and what entities must be legally responsible for meeting those measures.
The EPA is proposing that an existing source that becomes subject to requirements under CAA section 111(d) will continue to be subject to those requirements even after it undertakes a modification or reconstruction. Under this interpretation, a modified or reconstructed source would be subject to both (1) the CAA section 111(d) requirements that it had previously been subject to and (2) the modified source or reconstructed source standard being promulgated under CAA section 111(b) simultaneously with this rulemaking. It should be noted that this proposal applies to any existing source subject to any CAA section 111(d) plan, and not only existing sources subject to the CAA section 111(d) plans promulgated under this rulemaking.
As noted above, a “new source” is defined under CAA section 111(a)(2) as “any stationary source, the construction or modification of which is commenced after,” in general, a proposed or final CAA section 111(b) rule becomes applicable to that source; and under
Because CAA section 111(d) does not address whether an existing source that is subject to a CAA section 111(d) program remains subject to that program even after it modifies or reconstructs, the EPA has authority to provide a reasonable interpretation, under the Supreme Court's decision in
The EPA invites comments on this interpretation of CAA section 111(d)(1), including whether this interpretation is supported by the statutory text and whether this interpretation is sensible policy and will further the goals of the statute. It should be noted that this interpretation is severable from the rest of this rulemaking, so that if the EPA revises this interpretation in the final rule or if the EPA adopts this interpretation in the final rule but it is invalidated by a Court, there would be no effect on the rest of this rulemaking.
This section describes proposed state plan requirements related to the timing of achieving emission performance goals, including performance demonstrations, performance periods, and interim progress milestones.
As previously discussed, the goals are derived from application of four “building blocks.” The EPA has based the application of some of these measures to reduce CO
Section VIII.B.1.a of this preamble provides an overview of the proposals for state plan performance demonstrations and timing of emission reductions. Subsequent subsections include proposals for the start date for the interim goal performance period, the duration of the performance periods for the final and interim goals, interim progress milestone requirements, consequences if actual emission performance does not meet the state goal, and out-year requirements for states to maintain CO
As described previously, the agency is proposing final state-specific goals (specified in Table 8) that represent emission rates to be achieved by 2030, as well as interim goals, to be achieved on average over the 10-year period from 2020-2029. The agency is also proposing that emission performance levels consistent with the final state-specific goals be maintained after 2030.
This relatively long planning and implementation period provides states with substantial flexibility regarding methods and timing of achieving emission reductions. States may wish to make adjustments to their implementation approaches along the way, or as conditions change may need to make adjustments to ensure that their plans achieve the goals as intended. As a result, the agency envisions that the EPA, states, and affected entities will have an ongoing relationship in the course of implementing this program.
The EPA proposes that a state plan must demonstrate projected achievement of the emission performance levels in the plan, and these emission performance levels must be equivalent to or better than the interim and final goals established by the EPA. Specifically, the state plan must demonstrate that the projected emission performance of affected EGUs in the state will be equivalent to or better than the applicable interim goal during the 2020-2029 period, and equivalent to or better than the applicable final goal during the year 2030. The state plan must identify requirements that continue to apply after 2030 and are likely to maintain continued emission performance by affected EGUs that meets the final goal; however, quantitative projections of emission performance by affected EGUs
In addition to demonstrating that projected plan performance will meet the interim and final state goals, the EPA proposes that state plans must contain requirements for tracking actual plan performance during implementation. For plans that do not include enforceable requirements for affected EGUs that ensure achievement of the full level of required emission performance and interim progress, the state plans would be required to include periodic program implementation milestones and emission performance checks, and include corrective measures to be implemented if mid-course corrections are necessary. The state plan would provide for continued tracking of emission performance after 2030, and for corrective measures if the emission performance of affected EGUs in the state did not continue to meet the 2030 final goal during any three-year performance period.
The rationale for this approach is that it would ensure that states design their plans in a way that considers both the interim and final goals. If only the interim goal were considered, a state plan might not be sufficient to achieve the final goal.
The agency requests comment on a second option in which, in addition to submitting a plan demonstrating emission performance through 2030, states would be required to make a second submittal in 2025 showing whether their plan measures would maintain the final-goal level of emission performance over time (as further described below). If not, the state submittal would be required to strengthen or add to measures in the state plan to the extent necessary to maintain that level of performance over time.
The EPA also requests comment on whether 2025, or an earlier or later year, would be the optimal year for a second plan submittal under the second option.
A performance period is a period for which the state plan must demonstrate that the required emission performance level will be met. The EPA proposes a start date of January 1, 2020, for the interim goal plan performance period.
In considering the start date, it is relevant to consider the due dates for state plan submittals and the amount of time available for program implementation by the start date. January 2020 is 3.5 years from the proposed June 2016 deadline for initial plan submittals, 2.5 years from the proposed June 2017 extended deadline for complete plans from states not participating in a multi-state plan, and 1.5 years from the proposed June 2018 extended deadline for complete plans from states participating in a multi-state plan. The EPA suggests that affected entities may have greater lead time for compliance than might be implied by the plan submittal dates referenced above. Affected entities will have knowledge of state requirements as they are adopted, and the state must adopt rules and requirements in advance of submitting its complete plan to the EPA. Also, as explained in detail in subsection c, states may choose a different emission performance improvement trajectory from that which the EPA assumes for purposes of calculating state goals, achieving lesser levels of performance in early years and more in later years, provided, of course, that the interim 10-year average requirement is met.
The EPA proposes that a 2020 start date for the interim goal plan performance period is achievable in light of the following additional considerations. First, existing state programs will play a role in helping to achieve this rule's proposed emission performance levels. Second, in advance of this proposal, many states already were contemplating design of strategies that would achieve CO
For example, the EPA expects that many EGUs will meet their requirements in part by implementing heat rate improvements, and those actions may be undertaken promptly. The plant operations and maintenance (O&M) and engineering solutions used to improve heat rates at existing EGUs have long been commercially available and have been implemented at EGUs for many years. Further, the relatively modest capital costs (average $100/kW) and significant fuel savings associated with a suite of heat rate improvement (HRI) methods result in this measure being a low-cost approach to reducing CO
Dispatch changes, which are largely driven by the variable cost of operating a given EGU, occur on an hourly basis in the power sector. The average availability factor for NGCCs in the U.S. generally exceeds 85 percent, and can exceed 90 percent for selected groups.
Building Block 3 is based on shifting generation from affected fossil units to new renewable energy generating capacity, which is added over time, and new or preserved nuclear capacity, all of which is expected to be in place by 2020 (see the GHG Abatement Measures TSD for more information).
Finally, there is considerable experience with the states and the power sector in designing and implementing demand-side energy efficiency improvement strategies and programs. It is also well accepted that such improvements can achieve reductions in CO
The EPA recognizes that a state's circumstances and choice of emission reduction strategies may affect the timing of CO
As described in Section VII of the preamble, the EPA is proposing state-specific CO
The EPA proposes the following as the preferred option for the final and interim goal performance periods. As further explained below, this option reflects three main objectives: (1) Provide states with timing flexibility during the interim goal period to accommodate differences in state adoption processes and types of state programs, (2) ensure that state plans are designed to achieve the final goal no later than 2030, and (3) provide flexibility for year-to-year variation in actual emission performance that may occur as the electricity system responds to economic fluctuations.
This proposed approach provides a 10-year performance period for the interim performance level. The 10-year period allows states flexibility for timing of program implementation as the state ramps up its programs to achieve the final performance level. Using the single year 2030 as the projected year for achievement of the final goal ensures that state plans are designed to achieve the final goal no later than 2030; providing a multi-year time frame for projected plan performance would inappropriately delay the requirement for a final-goal level of performance that the EPA's analysis shows is achievable at the end of the 10-year interim ramp-up period. Using 2030 also avoids overlap with the interim goal performance period. The rolling three-year performance periods for measuring actual plan performance against the final goal performance level are proposed in light of year-to-year variability in economic and other factors, such as weather, that influence power system operation and affect EGU CO
For a rate-based plan, 2020-2029 emission performance is an average CO
The agency invites comment on this and other approaches to specifying performance periods for state plans.
The EPA recognizes the importance of ensuring that, during the proposed 10-year performance period (2020-2029) for the interim goal, a state is making steady progress toward achieving the required level of emission performance. The EPA is proposing that certain types of state plans be required to have program implementation milestones to ensure interim progress, as well as periodic checks on overall emission performance leading to corrective measures if necessary.
Some types of plans are “self-correcting” in that they inherently
The EPA proposes that self-correcting plans need not contain interim milestones consisting of program implementation steps, because these state plans inherently require both interim progress and achievement of the full level of required emission performance in a manner that is federally enforceable against affected EGUs. Annual reporting of emission performance by the state, however, is required for all types of plans.
For plans that are not self-correcting, the EPA proposes that the state plan must identify periodic program implementation milestones (e.g., start of an end-use energy efficiency program, retirement of an affected EGU, or increase in portfolio requirements under a renewable portfolio standard) that are appropriate to the programs and measures included in the plan. If, during plan implementation, a state were to miss program implementation milestones in its plan, it would need to report the delay to the EPA, explain the cause, and describe the steps the state will take to accelerate subsequent implementation to achieve the planned improvements in emission performance. Depending on the severity of delay and the explanation, the EPA could ultimately evaluate actions under CAA authorities to ensure timely program implementation.
In addition, we propose that the state and the EPA would track state plan emission performance on an ongoing basis, with states reporting performance data to the EPA annually by July 1. During the interim performance period, beginning in 2022, the state would be required each year to include a comparison of emission performance achieved to performance projected in the state plan. Each comparison would cover the preceding two-year period. The EPA may also approve regular, periodic emission comparison checks with a different frequency or comparison period to reflect the design of a state's programs (e.g., compliance periods for EGUs under an emission limit).
A report and corrective measures would be required if an interim emission check showed that actual emission performance of affected entities was not within 10 percent of the performance projected in the state plan (i.e., for a rate-based plan, if the average emission rate of affected EGUs were 10 percent higher than plan projections, or for a mass-based plan, if collective emissions of affected EGUs were 10 percent higher than plan projections). In that event, the state would be required in its submission to explain reasons for the deviation (e.g., energy efficiency program not working as effectively as expected, prolonged extreme weather that had been unanticipated in electricity demand projections) and specify the corrective measures that will be taken to ensure that the required level of emission performance in the plan will be met. The state also would be required to implement those corrective measures as expeditiously as practical.
The agency proposes that states be given a choice regarding when to adopt into regulation the corrective measures that the state plan identifies for implementation in the event that state plan performance is deficient. First, the state could adopt corrective measures into regulation prior to plan submittal in a manner that enables the state to implement the measures administratively, without further legislation or rulemaking, if a performance deficiency occurs during plan implementation. This would expedite implementation of corrective measures once a deficiency is discovered. Second, the state could elect to wait to adopt into regulation the corrective measures identified in the plan until after a plan performance deficiency is discovered. The EPA proposes this choice in recognition of the fact that it may be challenging for states to fully adopt corrective measures in advance to address the possibility that their plan will not perform as projected. However, if a state makes the latter choice, the EPA proposes that the state must report the reasons for deficient performance and must implement corrective measures if actual emission performance was inferior to projected performance by eight percent or more (rather than 10 percent or more). The reason for the lower percentage trigger is to identify a gradually developing deficiency in plan performance earlier in time. Legislative and/or regulatory action to adopt corrective measures after a deficiency is discovered will take significant time. State processes to activate corrective measures should be triggered earlier if corrective measures are not adopted in regulation and ready to implement.
The EPA alternatively requests comment on whether states should be required to create legal authority and/or adopt regulations providing for corrective measures in developing the state plan. The agency requests comment generally on the conditions that should trigger corrective measure requirements. The agency also solicits comment on whether actual emission performance inferior to projected performance by ten percent (for plans with corrective measures adopted into regulation prior to complete plan submittal) is the appropriate trigger for requiring a state to report the reasons for deficient performance and to implement corrective measures. We are also soliciting comment on the range of five percent to fifteen percent. For plans without corrective measures adopted into regulation prior to complete plan submittal, the agency solicits comment on whether the proposed eight percent emission performance deviation trigger is appropriate. We also solicit comment on the range of five percent to ten percent.
The EPA proposes that the state will be required to compare actual emission performance achieved during the entire 10-year interim performance period (i.e., 2020-2029) against the interim goal. As noted above, beginning after 2032, the EPA proposes that the state be required to compare actual emission performance achieved against the final goal on a rolling three-year average basis (e.g., 2030-32, 2031-33, etc.). The EPA also requests comment on the milestone approach and emission performance checks outlined above in the context of the alternative 5-year performance period and the planning approach for alternative state goals, which is described below.
There are scenarios under which an approved state plan might fail to achieve a level of emission performance by affected EGUs that meets the state goal. Under some types of plans, a possible scenario is that despite successful plan implementation, emissions under the plan turn out to be higher than projected at the time of plan
The EPA believes that the emission guidelines should specify the consequences in the event that actual emission performance under a state plan does not meet the applicable interim goal in 2020-2029, or does not meet the applicable final goal in 2030-2032 or later, because CAA section 111(d) is not specific on this point. The agency requests comment on how the consequences should vary depending on the reasons for a deficiency in performance.
Specifically, the agency requests comment on whether consequences should include the triggering of corrective measures in the state plan, or plan revisions to adjust requirements or add new measures. The agency also requests comment on whether corrective measures, in addition to ensuring future achievement of the state goal, should be required to achieve additional emission reductions to offset any emission performance deficiency that occurred during a performance period for the interim or final goal. This concept has been applied, for example, in the Acid Rain Program under Title IV of the CAA; a source that has sulfur dioxide emissions exceeding the emission allowances that it holds at the end of the period for demonstrating compliance is required subsequently to obtain additional emission reductions to offset its excess emissions.
The EPA further requests comment on whether the agency should promulgate a mechanism under CAA section 111(d) similar to the SIP call mechanism in CAA section 110. Under this approach, after the agency makes a finding of the plan's failure to achieve the state goal during a performance period, the EPA would require the state to cure the deficiency with a new plan within a specified period of time (e.g., 18 months). If the state still lacked an approved plan by the end of that time period, the EPA would have the authority to promulgate a federal plan under CAA section 111(d)(2)(A).
The agency is determining state goals for affected EGU emission performance based on application of the BSER during specified time periods. This raises the question of whether affected EGU emission performance should only be maintained—or instead should be further improved—once the final goal is met in 2030. This involves questions of goal-setting as well as questions about state planning. In this section, the EPA proposes that a state must maintain the required level of performance, and requests comment on the alternative of requiring continued improvement.
The EPA believes that Congress either intended the emission performance improvements required under CAA section 111(d) to be permanent or, through silence, authorized the EPA to reasonably require permanence. Other CAA section 111(d) emission guidelines set emission limits to be met permanently. Therefore, the EPA is proposing that the level of emission performance for affected EGUs represented by the final goal should continue to be maintained in the years after 2030. The EPA is proposing a mechanism for implementing this objective, and is taking comment on an alternative option.
As noted above, the EPA proposes that the state plan must demonstrate that plan measures are projected to achieve the final emission performance level by 2030. In addition, the state plan must identify requirements that continue to apply after 2030 and are likely to maintain affected EGU emission performance meeting the final goal; however, quantitative projections of emission performance beyond 2030 would not be required under the proposed option. Instead, the EPA proposes that the state plan would be considered to provide for maintenance of emission performance consistent with the final goal if the plan measures used to demonstrate projected achievement of the final goal by 2030 will continue in force and not sunset.
The EPA also requests comment on an alternative approach to a state's pre-implementation demonstration that the final-goal level of performance will be maintained after 2030. Under this alternative, the state plan would be required to include projections demonstrating that emission performance would continue to meet the final goal for up to 10 years beyond 2030. This approach could be implemented through a second round of state plan analysis and submittals in 2025 to make the demonstration and strengthen or add measures if necessary. The EPA generally requests comment on appropriate requirements to maintain the emission performance of affected EGUs in years after 2030.
The EPA also requests comment on whether we should establish BSER-based state emission performance goals for affected EGUs that extend further into the future (e.g., beyond the proposed planning period), and if so, what those levels of improved performance should be. Under this alternative, the EPA would apply its goal-setting methodology based on application of the BSER in 2030 and beyond to a specified time period and final date. The agency requests comment on the appropriate time period(s) and final year for the EPA's calculation of state goals that reflect application of the BSER under this approach.
The EPA notes that CAA section 111(b)(1)(B) calls for the EPA, at least every eight years, to review and, if appropriate, revise federal standards of performance for new sources. This requirement provides for regular updating of performance standards as technical advances provide technologies that are cleaner or less costly. The agency requests comment on the implications of this concept, if any, for CAA section 111(d).
The EPA proposes that states have flexibility to choose between a rate-
A state that adopted a mass-based performance level for 2020-2029 would have two options for addressing any perceived need for emissions flexibility in light of anticipated electricity demand growth after 2029. The state either could adopt a rate-based performance level consistent with the final goal, or could adopt a mass-based performance level based on a translation of the rate-based final goal to a mass-based goal.
In Section VII, the EPA requests comment on alternative, five-year state emission performance goals for affected EGUs shown in Table 9. The alternative goals represent emission rates achievable on average during the 2020-2024 period, as well as emission rates to be achieved and maintained after 2024. These alternative goals are less stringent than the proposed goals in Table 8.
To accompany the alternative goals, the EPA requests comment on another approach for state plan performance periods. This approach would require state plans to demonstrate that the required interim emission performance level will be met on average by affected EGUs during the five-year 2020-2024 interim period, and that the alternative final goal be met no later than 2025. After plan implementation, actual emission performance would be compared with the alternative final goal on a three-year rolling average basis, starting with 2025-2027, in light of year-to-year variability in economic and other factors, such as weather, that influence power system operation and affect EGU CO
In connection with the alternative state goals, for the years after 2027, the EPA requests comment on the same “out-year” issues and concepts for maintaining or improving emission performance over time that are described above in Section VIII.B.2.f. The EPA requests comment on whether a state plan should provide for emission performance after 2025 solely through post-implementation emission checks that do not require a second plan submittal, or whether a state should also be required to make a second submittal prior to 2025 to demonstrate that its programs and measures are sufficient to maintain performance meeting the final goal for at least 10 years. In addition, the agency requests comment on the appropriate date for any second state plan submittal designed to maintain emission performance after the 2025 performance level is achieved.
The EPA is proposing to require the twelve plan components discussed in Section VIII.D of this preamble. We will evaluate the sufficiency of each plan based on the plan addressing those components and on four general criteria for a state plan to be approvable. The EPA proposes to use the combination of these twelve plan components and four general criteria to determine whether a state's plan is “satisfactory” under CAA section 111(d)(2)(A). First, a state plan must contain enforceable measures that reduce EGU CO
The agency also notes that a CAA section 111(d) state plan is not a CAA section 110 state implementation plan (SIP). Although there are similarities in the two programs, approvability criteria for CAA section 111(d) plans need not be identical to approvability criteria for SIPs.
In developing its plan, a state must ensure that the plan is enforceable and in conformance with the CAA. We are seeking comment on the appropriateness of existing EPA guidance on enforceability in the context of state plans under CAA section 111(d), considering the types of affected entities that might be included in a state plan.
As discussed in section VIII.F.1, the EPA is seeking comment on whether the agency should provide guidance on enforceability considerations related to requirements in a state plan for entities other than affected EGUs (and if so, which types of entities). Also, as discussed in section VIII.F.4, the EPA intends to develop guidance for evaluation, monitoring, and verification (EM&V) of renewable energy and demand-side energy efficiency programs and measures incorporated in state plans.
A state plan must include enforceable CO
The EPA recognizes that a portfolio approach may result in enforceable state plan obligations accruing to a diverse range of affected entities beyond affected EGUs, and that there may be challenges to practically enforcing against some such entities in the event of noncompliance. We request comment
The second criterion for approvability is that the projected CO
We are proposing that states may demonstrate such emission performance by affected EGUs either on an individual state basis or jointly on a multi-state basis.
All of the emission reduction measures included in the agency's determination of the BSER reduce CO
However, emission limits for affected EGUs that are included in state plans could still include provisions that provide the ability to use GHG offsets for compliance with the emission limits, provided those emission limits would achieve the required level of emission performance for affected EGUs. We note that inclusion of such provisions would create a degree of uncertainty about the level of emission performance that would be achieved by affected EGUs when complying with the emission limit (as potentially would other flexibility mechanisms included in an emission limit). As a result, such emission limits would not be considered “self-correcting” as discussed above at Section VIII.B.2.d.
All existing state emission budget trading programs addressing GHG emissions include out-of-sector, project-based emission offsets, which may be used to cover a portion of the compliance obligation of affected sources. Other states may want to take a similar approach, for example, to incentivize GHG emission reductions from land use and agricultural waste management. How to address GHG offsets included in EGU emission limits when projecting emission performance under a state plan is addressed in the Projecting EGU CO
The ISO/RTO Council, an organization of electric grid operators, has suggested that ISOs and RTOs could play a facilitative role in developing and implementing region-wide, multi-state plans, or coordinated individual state plans. Existing ISOs and RTOs could provide a structure for achieving efficiencies by coordinating the state plan approaches applied throughout a grid region. Just as the ISO/RTO regions today share the benefits and costs of efficient EGU dispatch across state boundaries, there are significant efficiencies that could be captured by coordinating individual state plans or implementing multi-state plans within a grid region. Under one variant of this approach, states would implement a multi-state plan and jointly demonstrate CO
The third criterion for approvability is that a state plan specify how the effects of each state plan measure will be quantified and verified. The EPA proposes that all plans must specify how CO
For state plans that include other measures that avoid EGU CO
The fourth criterion for approval is that a state plan must (i) specify a process for annual reporting to the EPA of overall plan performance and implementation (including compliance of affected entities with applicable emission standards) during the plan performance periods, and (ii) include a process and schedule for implementing corrective measures if reporting shows that the plan is not achieving the projected level of emission performance. We solicit comment on whether the latter process should include the adoption of new plan measures and subsequent resubmission of the plan to the EPA for review and approval, or whether the process should specify the implementation of measures that are already included in the approved plan in the event that the projected level of performance is not being achieved. We also solicit comment on the point at which such a process and schedule would be triggered, such as at the end of a multi-year plan performance period if emission performance is not met, or at specified interim stages within a multi-year plan performance period. For plans with self-correcting mechanisms, the agency is not proposing that requirements for corrective measures be included in the plan. All of these considerations are addressed in more detail above in Section VIII.B.2.
The agency is also proposing that a state plan specify appropriate periodic reporting requirements for each affected entity in a state plan that will be reported at least annually, electronically, and disclosed on a state database accessible by the public and the EPA. The EPA is requesting comment on the appropriate scope of these reporting requirements and whether the reports should also be directly submitted by the affected
The EPA is proposing that an approvable plan must meet the approvability criteria described above and include the twelve state plan components summarized below, consistent with additional specific requirements explained elsewhere in this notice. Plans must comply with the EPA framework regulations at 40 CFR 60.23-60.29, except as specified otherwise by these emission guidelines. These requirements apply both to individual state plans and multi-state plans.
For states wishing to participate in a multi-state plan, the EPA is proposing that only one multi-state plan would be submitted on behalf of all participating states. The joint submittal would be signed by authorized officials for each of the states participating in the multi-state plan and would have the same legal effect as an individual submittal for each participating state. The joint submittal would adequately address plan components that apply jointly for all participating states and for each individual state in the multi-state plan, including necessary state legal authority to implement the plan, such as state regulations and statutes. Because the multi-state plan functions as a single plan, each of the required plan components described below (e.g., plan performance levels, program implementation milestones, emission performance checks, and reporting) would be designed and implemented by the participating states on a multi-state basis.
We are also seeking comment on two additional options for multi-state plan submittals. These options could potentially provide states with flexibility in addressing contingencies where one or more states submit plan components that are not approvable. In such instances, these options would simplify EPA approval of remaining common or individual portions of a multi-state plan. These options might also address contingencies during plan development where a state fails to finalize its participation in a multi-state plan, with minimal disruption to the submittals of the remaining participating states.
First, the EPA is seeking comment on whether states participating in a multi-state plan should also be given the option of providing a single submittal—signed by authorized officials from each participating state — that addresses common plan elements. Individual participating states would also be required to provide individual submittals that provide state-specific elements of the multi-state plan. Both the common multi-state submittal and each individual participating state submittal would be required to address all twelve plan components described below (even if only through cross reference to either the common submittal or individual submittals, as appropriate). Under this approach, the combined common submittal and each of the individual participating state submittals would constitute the multi-state plan submitted for EPA review.
Second, the EPA is seeking comment on an approach where all states participating in a multi-state plan separately make individual submittals that address all elements of the multi-state plan. These submittals would need to be materially consistent for all common plan elements that apply to all participating states, and would also address individual state-specific aspects of the multi-state plan. Each individual state plan submittal would need to address all twelve plan components.
The EPA proposes that each plan must have the following twelve components, except as indicated otherwise for self-correcting plans:
A state plan must list the individual affected EGUs in the state that are subject to the plan and provide an inventory of CO
The state plan must describe its approach and geographic scope, including whether the state will achieve its required level of CO
The state plan must identify the state's proposed emission performance level, which will either be the rate-based CO
A state plan must identify the rate-based or mass-based level of emission performance that must be met through the plan, (expressed in numeric values, including the units of measurement for the level of performance, such as pounds of CO
The EPA is proposing that multiple states could jointly demonstrate emission performance by affected EGUs. For these multi-state approaches, states would demonstrate emission performance by affected EGUs in aggregate with partner states. For states participating in a multi-state approach, the individual state performance goals in the emission guidelines would be replaced with an equivalent multi-state performance goal. For example, states taking a rate-based approach would demonstrate that all affected EGUs subject to the multi-state plan achieve a weighted average CO
The EPA is seeking comment on two options for calculating a weighted average, rate-based CO
Under the second option, the weighted average emission rate goal for a group of participating states is computed using each state-specific emission rate goal and the quantity of projected electricity generation by affected EGUs in each state. The calculation would be performed for the 2020 through 2029 period to produce a multi-state interim goal, and for 2030 to produce a multi-state final goal. This projection of electricity generation by affected EGUs would be for a reference case that does not include application of either the state-specific rate-based emission performance goals for the participating states or the requirements, programs, and measures included in the multi-state plan. This approach addresses the fact that the mix of generation among affected EGUs in different states could differ significantly during the plan performance periods from that during the 2012 base year. As a result, it would base the weighted average goal in part on the anticipated business-as-usual mix of generation by affected EGUs across the multiple states during the plan performance period. However, this approach could also significantly alter the weighted average performance goal based on projected retirements of affected EGUs in one or more states.
Under both options, the rate-based multi-state goal could be translated to a mass-based goal. These options, and the procedure for translation to a mass-based goal, are discussed in more detail in the Projecting EGU CO
We are requesting comment on whether, to assist states that seek to translate the rate-based goal into a mass-based goal, the EPA should provide a presumptive translation of rate-based goals to mass-based goals for all states, for those who request it, and/or for multi-state regions. As another alternative, the EPA could provide guidance for states to use in translating a rate-based goal to a mass-based goal for individual states and for multi-state regions. This could include information about acceptable analytical methods and tools, as well as default input assumptions for key parameters that will likely influence projections, such as electricity load forecasts and projected fossil fuel prices. Under this approach, the EPA might also provide a coordinating function in addressing the assumptions applied by multiple states within a grid region, acknowledging that assumptions about state programs across a broader grid region that are included in an analysis scenario may influence projections of CO
Technical considerations involved in translating from rate-based goals to mass-based goals are discussed in detail in the Projecting EGU CO
A state plan must demonstrate that the actions taken pursuant to the plan are, when taken together, projected to achieve emission performance by affected entities that, on average, will meet the state's required emission performance level for affected EGUs during the initial 2020-2029 plan performance period, and will meet the required final emission performance level in 2030. This demonstration will include a detailed description of the analytic process, tools, and assumptions used to project future CO
As described in greater detail in Section VIII.B.2.d., state plans must include periodic programmatic milestones to show progress in program implementation if the plan is not self-correcting (i.e., does not inherently require both interim progress and the full level of required emission performance in a manner that is federally enforceable against affected EGUs). These programmatic milestones with specific dates for achievement should be appropriate to the programs and measures included in the plan.
In addition, the state plan demonstration will indicate the plan's intended trajectory of emission performance improvement. As described in Section VIII.B.2.d., each year during the interim performance period, beginning in 2022 the state must compare the collective emission performance achieved by affected entities in the state during the previous two-year period with performance projected in the state plan. If actual emission performance is not within 10 percent of original projections, the state must submit a report by the July 1 following the end of the two-year period (submitted as part of the state's annual report on plan performance described below in section VIII.D.10) to explain reasons for the deviation and specify the corrective actions that will be taken to ensure that the required level of emission performance in the plan will be met.
For a plan that does not include self-correcting mechanisms, the plan must also specify corrective measures that will be implemented if the state's progress in achieving its level of performance for affected EGUs falls short of what is projected under the plan, as well as a process and schedule for implementing any such measures. The agency requests comment on the amount of emission rate improvement or emission reduction that the corrective measures included in the plan must be designed to achieve (e.g., measures sufficient to address a 10 percent performance deficiency). The agency also seeks comment on whether the emission guidelines should establish a deadline for implementation of corrective measures (e.g., two years from the July 1 deadline described above for reporting the deficiency as part of the state's annual report on plan performance). Corrective measure provisions are discussed in more detail above in section VIII.B.2.d and in section VIII.B.2.f.
A state plan must identify the affected entities to which each emission standard applies (e.g., individual affected EGUs, groups of affected EGUs, all the state's affected EGUs in aggregate, other affected entities that are not EGUs), as well as any implementing and enforcing measures for such standards, and describe each emission standard and the process for demonstrating compliance with it pursuant to state regulations or another legal instrument, including the schedule
In developing its CAA section 111(d) plan, a state must ensure that its plan is enforceable and in conformance with the CAA. As discussed in section VIII.C.1, we are seeking comment on the appropriateness of existing EPA guidance on enforceability in the context of state plans under CAA section 111(d), considering the types of affected entities that might be included in a state plan.
As discussed in section VIII.F.1, the EPA is seeking comment on whether the agency should provide guidance on enforceability considerations related to requirements in a state plan for entities other than affected EGUs (and if so, which types of entities). Also, as discussed in section VIII.F.4, the EPA intends to develop guidance for evaluation, monitoring, and verification (EM&V) of renewable energy and demand-side energy efficiency programs and measures incorporated in state plans.
For each emission standard, a plan must describe how it is quantifiable, non-duplicative, permanent, verifiable, and enforceable with respect to an affected entity. An emission standard is quantifiable if it can be reliably measured, using technically sound methods, in a manner that can be replicated. These issues are discussed further in Section VIII.F.4 and in the State Plan Considerations TSD.
An emission standard is non-duplicative with respect to an affected entity if it is not already incorporated in another state plan, except in instances where incorporated in another state as part of a multi-state plan. An example of a duplicative emission standard would occur where recognition of avoided CO
An emission standard is permanent if the standard must be met for each applicable compliance year or period, or replaced by another emission standard in a plan revision, or the state demonstrates in a plan revision that the emission standard is no longer necessary for the state to meet its required emission performance level for affected EGUs.
An emission standard is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the state and the Administrator to independently evaluate, measure, and verify compliance with it. This is discussed further in Section VIII.F.4 and in the State Plan Considerations TSD. An emission standard is enforceable if: (1) It represents a technically accurate limitation or requirement and the time period for the limitation or requirement is specified, (2) compliance requirements are clearly defined, (3) the affected entities responsible for compliance and liable for violations can be identified, (4) each compliance activity or measure is practically enforceable in accordance with EPA guidance on practical enforceability (as discussed in Section VIII.F.1 of this preamble), and the Administrator and the state maintain the ability to enforce against violations and secure appropriate corrective actions pursuant to CAA sections 113(a)-(h).
The state plan must describe the CO
Most affected EGUs already monitor CO
We are also proposing monitoring and reporting protocols for net energy output under 40 CFR Part 75 that would allow the ECMPS to be used for purposes of meeting the net energy output reporting requirement. Affected facilities with multiple generators (e.g., combined cycle facilities) would be required to report the electric output from all generators. The proposed protocols include a default apportionment procedure for multi-EGU facilities under which the net generation of each EGU at the facility would be determined as the net generation of the facility multiplied by the ratio of the EGU's gross generation to the sum of the gross generation for all EGUs at the facility. (In the case of EGUs producing both electric energy output and useful thermal output, the apportionment procedure would include a thermal-to-electric energy conversion calculation as provided in the proposed EGU GHG NSPS regulations.
A state plan that contains other emission standards, in addition to emission limits applicable to affected EGUs, must include additional reporting and recordkeeping requirements related to these other measures. These reporting and recordkeeping requirements will consist of the data necessary for each affected entity to demonstrate compliance with its obligations. This could include, for example, reporting of MWh electricity savings achieved by an electric distribution utility under an end-use energy efficiency resource standard and utility compliance with requirements of the standard. These requirements might also include comparable reporting by an electric distribution utility of renewable energy certificates (RECs) held, or renewable energy purchased or generated, under a renewable energy portfolio standard, and compliance with the standard. This is discussed further in Section VIII.F.5 and the State Plan Considerations TSD.
The EPA is proposing that state plans must include a record retention requirement of ten years, and we request comment on this proposed timeframe.
A state plan must provide that the state will submit reports to the EPA detailing plan implementation and progress, including the actions taken by the state, affected EGUs, and any other affected entities under the plan; the status of compliance by affected EGUs and any other affected entities with their obligations under the plan; current aggregate and individual CO
While some of the proposed reporting requirements such as reporting of EGU emissions (which can be done through existing reporting mechanisms) would not place additional burdens on states, others may require assembling information that is being reported under state programs into a single report. For example, in the case of a rate-based state plan that calls for adjusting the actual emission rate of the state's affected EGUs based on emissions avoided through renewable energy or end-use energy efficiency programs, the requirement for comparing actual plan performance against projected plan performance requires the state to incorporate information on results achieved by those programs each year. This emission performance comparison serves as the basis for showing either that a state plan is on track or that corrective measures are needed. Another reporting element is a list of facilities and their compliance status. The EPA is requesting comment on the appropriate frequency of reporting of the different proposed reporting elements, considering both the goals of minimizing unnecessary burdens on states and ensuring program effectiveness. In particular, the agency requests comment on whether full reports containing all of the report elements should only be required every two years.
In addition, the EPA is soliciting comment on whether these reports should be submitted electronically, to streamline transmission.
A state plan must provide certification that a hearing on the state plan was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission pursuant to the requirements of the EPA framework regulations at 40 CFR 60.23-60.29.
The state must provide supporting material and technical documentation related to applicable components of the plan. In its plan, a state must adequately demonstrate that it has the legal authority for each implementation and enforcement component that it has included in its plan as part of a federally enforceable emission standard. A state can make such a demonstration by providing supporting material related to the state's legal authority used to implement and enforce each component of the plan, such as statutes, regulations, public utility commission orders, and any other applicable legal instruments.
A state plan must also provide analytical materials used in translating a rate-based goal to a mass-based goal (if a translation is included), analytical materials used in projecting emission performance that will be achieved through the plan, relevant implementation materials, and any additional technical requirements and guidance the state proposes to use to implement elements of the plan.
Under the framework regulations, state plans would be due nine months after finalization of the emission guidelines. 40 CFR 60.23(a)(1). The President in his June 25, 2013 Memorandum specified that states should submit plans by June 30, 2016, which would provide states thirteen months. During the outreach process, many states expressed concern that this was not sufficient time to prepare and submit a state plan to the EPA. States commented that additional time was needed to accommodate, among other things, state legislative and rulemaking schedules, coordination among states involved in multi-state plans, coordination with third parties, and the complex technical work needed to develop a state plan. The EPA recognizes that state administrative procedures can be lengthy, some states may need new legislative authority, and states planning to join in a multi-state plan will likely need more than thirteen months to get necessary elements in place. Balanced against that concern, however, is the urgency of addressing carbon emissions and the fact that there are certain steps we believe states can take within thirteen months to set themselves on a clear path to adoption of a complete plan. Therefore, the EPA is proposing a plan submittal process with a submittal date of June 30, 2016 (thirteen months after the expected finalization date of the emission guidelines), which provides additional time to submit a complete plan to the EPA after June 30, 2016, when justified. Part of that justification would include the state's demonstration of having taken meaningful steps during the first thirteen months toward submitting a complete plan. This approach involves the option that we refer to as an initial submittal, followed by submittal of a complete state plan no later than either June 30, 2017 for single-state plans or June 30, 2018 for multi-state plans.
In addition, for states wishing to participate in a multi-state plan, the EPA is proposing that only one multi-state plan would be submitted on behalf of all participating states, provided it is signed by authorized officials for each of the states participating in the multi-state plan and contains the necessary regulations, laws, etc. for each state in the multi-state plan. In this instance, the joint submittal would have the same legal effect as an individual submittal for each participating state.
The EPA framework regulations (40 CFR 60.23) require that state plans be submitted to the EPA within nine months of promulgation of the emission guidelines, unless the EPA specifies otherwise.
The EPA proposes that approvable justifications for seeking an extension beyond 2016 for submitting a complete plan include: A state's required schedule for legislative approval and administrative rulemaking, the need for multi-state coordination in the development of an individual state plan, or the process and coordination necessary to develop a multi-state plan. The EPA is requesting comment on other circumstances for which an extension of time would be appropriate. We are also seeking comment on whether some justifications for extension should not be permissible.
If a state submits an initial state plan by June 30, 2016, and it meets the minimum requirements for an initial state plan, as specified in the plan guidelines, then the deadline extension for submitting a complete plan that the state requested will be deemed granted. If the EPA determines that the initial plan does not meet the guidelines, the EPA will notify the state by letter, within 60 days, that the agency cannot approve the state's initial plan as submitted. The EPA believes this approach is authorized by, and consistent with, section 60.27(a) of the implementing regulations.
If the EPA approves a two-year extension to June 30, 2018, for a state developing a multi-state plan, the state would be required to provide one update, on June 30, 2017, on its progress toward milestones and schedules in the initial plan for developing and submitting a complete plan. We are requesting comment on this approach and the timing and frequency of updates that the state must provide.
As noted, if a state is unable to prepare and submit a complete plan by June 30, 2016, the state must make an initial submittal by that date. To be approved, the EPA proposes that the initial plan must address all components of a complete plan, including identifying which components are not complete. For incomplete components, an approvable initial submittal must contain a comprehensive roadmap outlining the path to completion, including milestones and dates. We recognize that certain options that states may choose involve more analytic effort to precisely demonstrate sources of emission reductions than other options.
The EPA is proposing that the state must provide an opportunity for public comment on a substantial draft of its initial submittal. The EPA proposes that this public comment opportunity will not be governed by the procedural requirements of the framework regulations that apply to the state's adoption of a complete plan, such as the requirement that the state hold a public hearing. 40 CFR 60.23(c)-(f). An initial plan might not include any legally enforceable provisions that the state would have adopted through its administrative or legislative processes, which generally provide for public input. Therefore, to ensure that the public has an opportunity to understand and inform the initial plan, the EPA is proposing that prior to submittal on June 30, 2016 the state must have provided a reasonable opportunity for public comment on a substantial draft of the initial submittal, with notice to the EPA of that comment period. The EPA can use this comment opportunity to advise the state whether it is on track to submit an approvable initial plan. When the state submits its initial plan, it must provide the EPA with a response to any significant comments it received on issues relating to the approvability of the initial plan so that the EPA can fully assess whether it is approvable.
To be approvable, the initial plan must include the following information:
• A description of the plan approach and progress to date in developing a complete plan.
• Initial quantification of the level of emission performance that will be achieved through the plan.
• A commitment to maintain existing measures that limit or avoid CO
• A comprehensive roadmap for completing the plan, including process, analytical methods, and schedule (with milestones) specifying when all necessary plan components will be complete (e.g., demonstration of projected plan performance; implementing legislation, regulations and agreements; any necessary approvals).
• Identification of existing programs, if any, the state intends to rely on to meet its emission performance level.
• Identification of executed agreements with other states (e.g., memorandum of understanding (MOU)), if a multi-state approach is being pursued.
• A commitment to submit a complete plan by no later than the applicable required date and explanation of actions the state will take to show progress in addressing incomplete plan components.
• A description of all steps the state has already taken in furtherance of actions needed to finalize a complete plan (e.g., copies of draft or proposed regulations, draft or introduced legislation, or draft implementation materials).
• Evidence of an opportunity for public comment and a response to any significant comments received on issues relating to the approvability of the initial plan.
The EPA is soliciting comment on whether there are other elements that a state must include in its initial submittal to qualify for a date extension. Specifically, the EPA requests comment on whether the guidelines should require a state to have taken significant, concrete steps toward adopting a complete plan for the initial plan to be approvable. For example, while it may be difficult for a state to complete its administrative or legislative process within thirteen months, it may be reasonable to require that a state must document that it has at least proposed any necessary regulations and introduced any necessary legislation within the first thirteen months to qualify for additional time to submit a complete plan.
For states participating in a multi-state program, the initial submittal should include executed agreements among the participating states and a road map for both design of the multi-state program and its implementation at the state level. The RGGI provides an example of such an approach. The RGGI participating states signed a Memorandum of Understanding (MOU) in December 20, 2005, in which the states “express[ed] their mutual understandings and commitments”.
Following the June 30, 2016, deadline for state plan submittals, the EPA will review plan submittals for approvability. For a state that submits an initial state plan by June 30, 2016, and requests an extension of the deadline for the submission of a complete state plan, the EPA will determine if the initial plan submittal meets the minimum requirements for an initial state plan. If it meets the minimum requirements for an initial state plan, as specified in the emission guidelines, the state's request for a deadline extension to submit a complete plan will be deemed granted, and the complete plan must be submitted to the EPA by no later than June 30, 2017 or June 30, 2018 as appropriate.
After receipt of a complete plan submittal, the EPA proposes that the agency will review the plan and, within twelve months, approve or disapprove the plan through a notice-and-comment rulemaking process, similar to that used for approving state implementation plan submittals under section 110 of the CAA. The framework regulations currently provide for the EPA to act on a complete plan within four months. 40 CFR 60.27(b). The EPA proposes that for plans under these guidelines, the agency will act on a complete plan within twelve months to provide adequate time for rulemaking procedures.
Currently, the EPA's framework regulations do not explicitly provide for the EPA to use the different forms of approval actions Congress introduced into the SIP program in the 1990 Clean Air Act Amendments. The EPA is taking comment on whether, for complete state plans under these guidelines, the agency may use two approval mechanisms provided for in CAA sections 110(k)(3) and (4), 42 U.S.C. 7410(k)(3) and (4). CAA section 111(d)(1) provides that the EPA shall establish “a procedure similar to that provided by section 7410 of this title [section 110 of the Act].” The EPA is considering whether to update the procedures for acting on complete state plans under the guideline to reflect the enhancements Congress included in CAA section 110 for agency actions on state implementation plans.
The first mechanism is a partial approval/partial disapproval. Where a CAA section 111(d) plan includes severable provisions, some of which are approvable and some of which are not, the EPA is taking comment on whether the agency should interpret the CAA as providing the flexibility to approve those elements that meet the requirements of this guideline, while disapproving those elements that do not. Any plan that is partially approved and partially disapproved would not fully discharge the state's obligation to submit a fully approvable plan, but the partial approval would make federally enforceable those elements of the state's plan that comply with these guidelines.
The second mechanism is a conditional approval. Where a CAA section 111(d) plan is substantially approvable and requires only minor amendments to fully meet the requirements of these guidelines, the EPA is taking comment on whether the agency should interpret the CAA as providing the flexibility to approve that plan on the condition that the state commits to curing the minor deficiencies within one year. Any such conditional approval would be treated as a disapproval if the state fails to comply with its commitment. During the year following the conditional approval while the state works to cure
The EPA has seen that these mechanisms have proven useful when reviewing and acting on state implementation plan submittals under CAA section 110. They allow the state, the EPA, and citizens to enforce good elements of plans or plans that are substantially complete while the state and the EPA work together to put in place a fully approvable plan. The agency notes that complete plan submittals under these guidelines, like SIPs that implement air quality standards, also may contain multiple program elements.
If a state fails to submit a complete plan by the applicable deadline, the EPA will notify the state by letter of its failure to submit. The EPA will publish a
During the course of implementation of an approved state plan, a state may wish to update or alter one or more of the enforceable measures in the state plan, or replace certain existing measures with new measures. The EPA proposes that the state may revise its state plan provided that the revision does not result in reducing the required emission performance for affected EGUs specified in the original approved plan. In other words, no “backsliding” on overall plan emission performance through a plan modification would be allowed.
If the state wishes to revise enforceable measures in its approved state plan, the EPA proposes that the state must submit the revised enforceable measures to the EPA and demonstrate that the revised set of enforceable measures in the modified plan will result in emission performance at affected EGUs that is equivalent to or better than the level of emission performance required by the original state plan. In the case of minor changes to enforceable measures, this showing may be a simple explanation of why the changes will not alter the emission performance of affected EGUs under the state plan, or will clearly improve the emission performance of affected EGUs under the state plan. In the case of more substantive changes to enforceable measures, or substitution of a new measure for an old measure, new projections of emission performance under the modified plan would be needed to demonstrate that the modified plan will meet the required level of emission performance for affected EGUs specified in the original approved plan. The EPA requests comment on whether, for such new projections of emission performance, the projection methods, tools, and assumptions used should match those used for the projection in the original demonstration of plan performance, or should be updated to reflect the latest data and assumptions, such as assumptions for current and future economic conditions and technology cost and performance.
The EPA is seeking comment on the creation of a template for initial and complete state plan submittals. A plan template would provide a framework that includes all of the necessary components for an initial and complete submittal that could be populated by states. This could assist states in compiling their plan submittals and streamline EPA review by assuring greater consistency in the format and organization of submittals. This would provide greater certainty for states about what they need to include in a submittal and allow the EPA to provide a quicker response to states about the completeness and approvability of submittals. We are further seeking comment on whether a template may be more appropriate for initial plan submittals than complete plans. Initial plan submittals are likely to be more similar across states, compared to complete plans, which may include a diverse range of components, depending on the state plan approach.
The EPA is also seeking comment on whether it should provide for, or require, electronic submittal of initial and complete plans. It is the EPA's experience that the electronic submittal of information increases the ease and efficiency of data submittal and data accessibility. We note that a number of states have requested an electronic submittal process for state implementation plans (SIPs) under CAA section 110, and the EPA has implemented a pilot program with a number of states for electronic submittal of such plans. The Electronic State Implementation Plan Submission Pilot (eSIPS) includes an EPA-state workgroup that has developed and will evaluate an electronic submission process. This pilot will use the EPA's Central Data Exchange (CDX) electronic submission system. We are seeking comment on the suitability of such an approach for submittal of state plans under CAA section 111(d).
The EPA is proposing to give states broad discretion to develop plans that best suit their circumstances and policy objectives. In developing its plan, a state will need to make a number of decisions that will require careful consideration, in order to ensure that its plan both meets the state's policy objectives and is approvable by the EPA. In this section, we identify several key decision points and factors that states should consider when developing their plans.
The EPA has also prepared a TSD, titled “State Plan Considerations,” that provides further information on these topics. The agency is seeking comment on the contents of this TSD and all aspects of the state plan decision points and factors below.
A state will need to identify each affected entity responsible for meeting compliance obligations under its plan and the means by which compliance with each plan requirement will be met, as well as demonstrate that it has the legal authority to subject such entities to the federally enforceable requirements specified in its state plan. We are proposing that affected entities in an approvable state plan may include: An owner or operator of an affected EGU, other affected entities with responsibilities assigned by a state (e.g., an entity that is regulated by the state, such as an electric distribution utility, or a private or public third-party entity), and a state agency, authority or entity. We are seeking comment on other appropriate examples of affected entities beyond the affected EGUs.
While the EPA seeks to provide states with broad discretion to develop plans that best suit their circumstances and policy objectives, a plan that assigns responsibility to affected entities other than affected EGUs may be more challenging to implement and enforce than a plan with requirements assigned only to affected EGUs.
Furthermore, it may be more challenging for a state to demonstrate that it has sufficient legal authority to subject such affected entities other than affected EGUs to the federally enforceable requirements specified in its state plan. We seek comment on whether the EPA should provide guidance on enforceability considerations related to requirements in a state plan for affected entities other than EGUs (and if so, which such entities). The State Plan Considerations
Many state officials and stakeholders have said that the EPA should avoid structuring the CAA section 111(d) emission guidelines in a way that would disadvantage states that already have adopted programs that reduce CO
There is much less agreement among states and stakeholders on the specifics of how existing state programs should be treated in a demonstration that a proposed state plan will achieve the required level of emission performance.
The EPA, starting from recent historical data, has identified the affected EGU emission performance improvements and resulting average emission performance levels for affected EGUs that are achievable, considering cost, in each state over the 2020-2029 period, with achievement of the final CO
As explained in Section VII above, the EPA's proposed state-specific goals reflect actions that many states have already taken to reduce or avoid EGU CO
The agency recognizes that states that have already shifted toward lower carbon-intensity generation or ramped up demand-side EE programs are better positioned to meet state-specific goals. For example, states where significant shifts in generation to NGCC units have already occurred would be closer to the generation mix reflected in the state goals than states where NGCC capacity is not yet being operated to the same degree. Likewise, states with relatively well-established demand-side EE programs would be able to build on those programs more quickly than states with less established programs, and would be closer to, or in some cases already achieving, the level of demand-side energy efficiency reflected in the state goals.
The EPA is proposing that existing state programs, requirements, and measures,
Specifically, the EPA is proposing that, for an existing state requirement, program, or measure, a state may apply toward its required emission performance level the emission reductions that existing state programs and measures achieve during a plan performance period as a result of actions taken after the date of this proposal.
In general, the agency has identified two broad options for treatment of existing state programs and measures. As noted above, the EPA proposes that emission reductions that existing state requirements, programs and measures achieve during a plan performance period as a result of actions taken after a specified date may be recognized in determining emission performance under a state plan. While proposing that the “specified date” would be the date of proposal of these emission guidelines, the EPA also requests comment on the following alternatives: The start date of the initial plan performance period, the date of promulgation of the emission guidelines, the end date of the base period for the EPA's BSER-based goals analysis (e.g., the beginning of 2013 for blocks 1-3 and beginning of 2017 for block 4, end-use energy efficiency), the end of 2005, or another date.
For this option, we are seeking comment on the point in time after which such actions should be able to qualify for use during a plan performance period, considering the method used to set state goals. Whether this option is consistent in practice with the EPA's application of the BSER may depend on the date or dates that are applied for qualifying actions under existing state programs, requirements, and measures. For example, implementation of measures subsequent to the proposal or promulgation of the emission guidelines may be consistent with a forward-looking goal-setting approach, as these actions may be necessary to meet a required level of emission performance during the plan performance period or will put a state in a better position to meet the required level of performance. An example is the EPA's treatment of end-use energy efficiency potential in state goal-setting, where the energy savings achievable during the initial plan performance period are premised in part on a ramping up of end-use energy efficiency programs and cumulative energy savings prior to the beginning of the plan performance period. Earlier dates may also be consistent with a forward-looking goal-setting approach, if the goal-setting approach is premised in part on actions that could be taken prior to the initial plan performance period. However, inconsistency issues may arise if the selected date is not adequately synchronized with the goal-setting method. The EPA requests comment on whether there is a rational basis for choosing a date that predates the base period from which the EPA used historical data to derive state goals. The agency generally requests comment on the appropriate date to select under this option.
The EPA also solicits comment on a second broad option. This option would recognize emission reductions that existing state requirements, programs
The EPA requests comment on this option—that emission reduction effects that occur prior to the beginning of the initial plan performance period could be applied toward meeting the required level of emission performance in a state plan. This approach would enable a state to count emission improvements achieved by state programs prior to 2020 toward its interim goal, allowing the state to begin demonstrating emission performance earlier and follow a more gradual emission improvement trajectory during the interim performance period of 2020-2029. This approach would in effect allow higher emissions during the 2020-2029 period than would occur under the proposed approach (i.e., requiring less emission performance improvement during that period). The rationale for this approach would be that higher emissions in 2020-2029 would be offset by pre-2020 emission reductions not required by the CAA section 111(d) program. However, total emissions to the atmosphere would likely be greater under this approach, unless the pre-2020 emission reductions that can be counted toward the state goal are limited to reductions that would not have occurred in the absence of the CAA section 111(d) program. To the extent that states are able to both adopt and implement new requirements earlier than 2020 (e.g., by 2018 or 2019), this approach could provide an incentive for earlier emission reductions. The agency requests comment on whether pre-2020 implementation of new requirements would be practical for states. The agency generally requests comment on this approach, including the conditions that should apply to pre-2020 emission reductions that would count toward the state goal.
The agency also requests comment on the alternative dates listed above in connection with this option. We also request comment on whether this option is inconsistent with the forward-looking method that the EPA has proposed for establishing state goals based on the application of the BSER.
The agency is seeking comment on whether some variation of this approach could be justified as consistent with the EPA's proposed goal-setting approach, as well as the general concept of the BSER and its application in establishing state goals. In particular, we are seeking comment on whether the emission effects of actions that are taken after proposal or promulgation of the emission guidelines or the approval of a state plan, but which occur prior to the beginning of the initial state plan performance period, could be applied toward meeting the required level of emission performance in a state plan.
Under a rate-based approach, the options described above would address the eligibility date for qualifying demand-side EE measures that, through MWh savings, avoid CO
Under a mass-based approach, the options described above would be applied when establishing a reference case scenario projection that is used to translate a rate-based goal to a mass-based goal. For example, demand-side EE measures after a respective eligibility date would not be included in the scenario that is used to project CO
We are proposing that RE and demand-side EE measures may be incorporated into a rate-based approach through an adjustment or tradable credit system applied to an EGU's reported CO
Under this approach, affected EGUs
We are seeking comment on different approaches for providing such crediting or administrative adjustment of EGU CO
Credits or adjustment might represent avoided MWh of electric generation or avoided tons of CO
A MWh crediting or adjustment approach implicitly assumes that the avoided CO
An alternative approach is to provide an adjustment based on the estimated CO
In addition, because some of the CO
A key consideration for state plans is the process and requirements under a state plan for quantifying, monitoring, and verifying the effect of RE and demand-side EE measures that result in electricity generation or electricity savings.
The EPA is proposing that a state plan that includes enforceable RE and demand-side EE measures must include an evaluation, measurement, and verification (EM&V) plan that explains how the effect of these measures will be determined in the course of plan implementation. An EM&V plan will specify the analytic methods, assumptions, and data sources that the state will employ during the state plan performance periods to determine the energy savings and energy generation related to RE and demand-side EE measures. An EM&V plan would be subject to EPA approval as part of a state plan. As discussed below, the EPA intends to develop guidance on acceptable EM&V methods that could be incorporated in an approvable EM&V plan that is included as part of an approvable state plan.
Utilities and states have conducted ongoing EM&V of demand-side EE and RE measures and programs for several decades. Current practice with EM&V for RE and demand-side EE programs in the U.S. is primarily defined by state public utility commission (PUC) requirements for customer-funded energy efficiency and renewable energy programs, as well as related compliance and reporting requirements for EERS and renewable portfolio standards (RPS).
The level of PUC oversight of demand-side EE programs varies from state to state, but this oversight process has generated the majority of the industry guidance and protocols for documenting energy savings from EE programs. Typically, impact evaluation reports are responsive to requirements established by PUCs and submitted (usually annually) for PUC review, approval, and use in resource planning and performance assessment. These PUC requirements generally rely upon a well-defined set of industry-standard practices and procedures. In states with the most experience implementing and overseeing demand-side EE programs, this typically includes: Use of one or more industry-standard EM&V protocols or guidelines; use of “deemed savings values,”
Despite this well-defined and generally accepted set of industry practices, many states with energy efficiency programs use different input values and assumptions in applying these practices (e.g., net versus gross savings,
For RE measures and programs, EM&V employed by states and utilities commonly relies upon a set of standard practices and procedures, such as the use of revenue-quality meters for quantifying RE generation. As a result, existing state and utility requirements and processes for quantification, monitoring, and verification of RE programs and measures generally provide a solid foundation for minimum requirements or guidance established by the EPA for state plans.
For both RE and demand-side EE measures included in state plans, additional information and reporting may be necessary to accurately quantify the avoided CO
Current state and utility EM&V approaches for RE and demand-side EE programs and mandates are discussed in more detail in the State Plan
In developing guidance, the agency does not intend to limit the types of RE and demand-side EE measures and programs that can be included in a state plan, provided that supporting EM&V is rigorous, complete, and consistent with the EPA's guidance. This approach recognizes differences among RE and demand-side EE programs and measures with respect to implementation history and experience, existence of applicable EM&V protocols and methods, and the nature and type of program oversight (e.g., whether or not a program is subject to PUC oversight). The EPA is requesting comment on the merits of this approach, including whether such guidance should identify types of RE and demand-side EE measures and programs for which evaluation of results is relatively straightforward and which are appropriate for inclusion in a state plan. Such approaches might be subject to streamlined review of EM&V protocols included in an approvable state plan, provided that such protocols are applied in accordance with industry best practices. For example, many utilities have implemented a similar core set of RE and demand-side EE measures and programs for utility customers. For these types of measures and programs, a substantial base of experience has been established nationally for the evaluation of measure and program outcomes. Other types of measures and programs, such as those that seek to alter consumer and building occupant behavior might pose quantification and verification challenges. Still other types of measures, such as state energy-efficient appliance standards and building codes, have not typically been subject to similar evaluation of energy savings results. These types of approaches might have substantial impacts, and the EPA does not want to discourage their implementation in state plans, but they might require development of appropriate quantification, monitoring, and verification protocols. The EPA and its federal partners intend to discuss the development of appropriate EM&V protocols for such measures with states in the coming years.
As an alternative to the EPA's proposed approach of allowing a broad range of RE and demand-side EE measures and programs to be included in state plans, provided that supporting EM&V documentation meets applicable minimum requirements, the EPA is requesting comment on whether guidance should limit consideration to certain well-established programs, such as those characterized in Section V.A.4.2.1 of the State Plan Considerations TSD.
If a state plan incorporates RE and demand-side EE measures under a rate-based approach or implements a mass-based portfolio approach with such measures, reporting and recordkeeping requirements for an approvable plan would differ from those applicable to an affected EGU. For example, these requirements may include compliance reporting by an electric distribution utility subject to an EERS or RPS. They may also include reporting by a vertically integrated utility implementing an approved integrated resource plan. In the latter instance, the utility might also be the owner and operator of affected EGUs, but additional reporting of quantified effects of RE and demand-side EE measures under the utility plan would be necessary to demonstrate emission performance under the state plan. In other instances, a state agency or entity or a private or public third-party entity might be implementing programs and measures that support the deployment of end-use energy efficiency and clean energy technologies that are incorporated into a state plan. In each of these instances, reporting of program compliance or program outcomes is a necessary part of an approvable plan to demonstrate emission performance under the plan.
Examples of potential reporting obligations for affected entities implementing RE and demand-side EE measures in an approvable state plan are provided in the State Plan Considerations TSD. We are seeking comment on the examples and suitability of potential approaches described in the TSD and any other appropriate reporting and recordkeeping requirements for affected entities beyond affected EGUs.
The electricity system and wholesale electricity markets are interstate in nature. EGUs in one state provide electricity to customers in neighboring states. Power companies often own EGUs in more than one state and manage them as a system. EGUs are dispatched both within and across state borders.
Similarly, programs and measures in a state plan, such as RE and demand-side EE measures, may affect the performance of the interconnected electricity system beyond a state border. In addition, many state programs allow for actions in neighboring states to meet the in-state requirement or explicitly address CO
The EPA recognizes the complexity of accounting for interstate effects associated with measures in a state plan in a consistent manner, to allow states to take into account the CO
The EPA is proposing that, for demand-side EE measures, consistent with the approach that the EPA used in determining the BSER, a state could take into account in its plan only those CO
The EPA is proposing that, for renewable energy measures, consistent with existing state RPS policies, a state could take into account all of the CO
The EPA is also seeking comment on how to avoid double counting emission reductions using this proposed approach. The agency is also proposing that states participating in multi-state plans could distribute the CO
As proposed, an approvable state plan will include a projection of CO
The EPA is striving to find a balance between providing state implementation flexibility and ensuring that the emission performance required by CAA section 111(d) is properly defined in state plans and that plan performance projections have technical integrity. Each state plan must include a projection of CO
The credibility of state plans under CAA section 111(d) will depend in large part on ensuring credible and consistent emission performance projections in state plans. Therefore, the use of appropriate methods, tools and assumptions for such projections is critical.
Considerations for projecting emission performance under a state plan will differ depending on the type of plan. This includes differences in how inputs to projections are derived; how projections are conducted, including tools, methods and assumptions; and how aspects of a plan are represented in these projections.
In general, any material component of a state requirement or program included in a state plan that could affect emission performance by affected EGUs should be accurately represented in emission projections included in the state plan.
For example, mass-based emission budget trading programs include a number of compliance flexibility mechanisms that might impact emission performance achieved by affected EGUs subject to these programs. These include multi-year compliance periods; the ability to bank allowances issued in a previous compliance period for use in a subsequent compliance period; the use of out-of-sector project-based emission offsets; and cost-containment allowance reserves that make additional allowances available to the market if pre-established allowance price thresholds are achieved. As a result, annual emissions from affected sources subject to an emission budget trading program often differ from the established annual emission budget for affected sources. In addition, these programs may be multi-sector in nature, regulating emissions for source categories in addition to EGUs. As a result, emission projections in state plans will need to accurately account for and represent these compliance flexibilities, as well as the scope of affected sources if they are broader than EGUs affected under CAA section 111(d). Similarly, other types of state programs, such as RPS, may include flexibility mechanisms or other provisions, such as alternative compliance payment mechanisms, banking, and limits on total ratepayer impact, that affect the ultimate amount of electricity generation required under the portfolio standard. These considerations for different types of state programs are discussed in more detail in the Projecting EGU CO
In general, as with projections used to determine a mass-based goal, projections of emission performance under a state plan could be conducted using historical data and parameters for estimating the future impact of individual state programs and measures. Alternatively, a projection could include modeling, such as use of a capacity planning and dispatch
These considerations, and considerations for projecting emission performance under different types of state plan approaches, are discussed in detail in the Projecting EGU CO
We are seeking comment on the considerations discussed in this TSD, including options presented for how projections might be conducted in an approvable state plan, and how different types of state plan approaches are represented in these projections. We are seeking further comment on whether the EPA should develop guidance that describes acceptable projection approaches, tools, and methods for use in an approvable plan, as well as providing technical resources for conducting projections.
The ISO/RTO Council, an organization of electric grid operators, has suggested that ISOs and RTOs could provide analytic support to help states develop and implement their plans. The ISOs and RTOs have the capability to model the system-wide effects of individual state plans. Providing assistance in this way, they felt, would allow states with borders that fall within an ISO or RTO footprint to assess the system-wide impacts of potential state plan approaches. In addition, as the state implements its plan, ISO/RTO analytic support would allow the state to monitor the effects of its plan on the regional electricity system. ISO/RTO analytic capability could help states assure that their plans are consistent with region-wide system reliability. The ISO/RTO Council suggested that the EPA ask states to consult with the applicable ISO/RTO in developing their state plans. The EPA agrees with this suggestion and encourages states with borders that fall within one or more ISO or RTO footprints to consult with the relevant ISOs/RTOs.
States may include measures in their plans beyond those that the EPA included in its determination of the BSER. In general, any measures that meet the proposed criteria for approvable state plans could be employed in a state plan. Beyond that, under a mass-based approach, any measure that reduces affected EGU emissions—even if not included in the state plan—will, if implemented during a plan performance period, help to achieve actual emissions performance that meets the required level.
Beyond the types of state plan measures already discussed in this section of the preamble, the agency has identified a number of other measures that could also lead to CO
In addition, technological advances and innovations in energy and pollution control technologies will continue over time. The agency is aware that as new technologies become available or as costs of a technology drop because of technical advances, states may wish to include measures in their state plans that make use of those technologies.
To be more specific, there are multiple potential measures that can be taken at an EGU beyond heat rate improvements that will reduce CO
In addition to the nuclear generation taken into account in the state goals analysis, any additional new nuclear generating units or uprating of existing nuclear units, relative to a baseline of capacity as of the date of proposal of the emission guidelines, could be a component of state plans. This baseline would be consistent with the proposed approach for treatment of existing state programs. The agency requests comment on alternative nuclear capacity baselines, including whether the date for recognizing additional non-BSER nuclear capacity should be the end of the base year used in the BSER analysis of potential nuclear capacity (i.e., 2012). In general, when considering nuclear generation in a state plan, states may wish to consider the impacts that different types of policies may have on different types of zero-emitting generation. Under a capped approach which does not provide any “crediting” for zero-emitting generation, the impact on all zero-emitting units should be the same. In a rate based approach that credited zero or low-emitting generation, the crediting mechanism used could result in different economic impacts on different types of zero- or low-emitting generation.
Another way that a state plan could reduce utilization and emissions from affected existing EGUs would be through construction of new NGCC—that is, NGCC on which construction commences after the date of proposal or finalization of CAA section 111(b) standards applicable to that source. (The agency's CAA section 111(d) proposal does not include new NGCC as a component of the BSER, but requests comment on that question in Section VI of this preamble.) Under a mass-based plan where an emission limit on affected EGUs would assure achievement of the required level of emission performance in the state plan, any emission reductions at affected EGUs resulting from substitution of new NGCC generation for higher-emitting generation by existing affected EGUs would automatically be reflected in mass emission reductions from affected EGUs. A state would not need to include enforceable provisions for new NGCC in its plan, under such an approach. However, under a mass-based portfolio approach, enforceable measures in a state plan might include
The agency requests comment on how emissions changes under a rate-based plan resulting from substitution of generation by new NGCC for generation by affected EGUs should be calculated toward a required emission performance level for affected EGUs. Specifically, considering the legal structure of CAA section 111(d), should the calculation consider only the emission reductions at affected EGUs, or should the calculation also consider the new emissions added by the new NGCC unit, which is not an affected unit under section 111(d)? Should the emissions from a new NGCC included as an enforceable measure in a mass-based state plan (e.g., in a plan using a portfolio approach) also be considered?
Similar to zero-emitting generation, states may also want to consider whether the policy design they choose sends similar or different price signals to new and existing NGCC. For instance, under a mass based program, if new NGCCs were not included, their costs would be less than the cost of an existing NGCC unit.
In respect to new fossil fuel-fired EGUs, the agency also requests comment on the concept of providing credit toward a state's required CAA section 111(d) performance level for emission performance at new CAA section 111(b) affected units that, through application of CCS, is superior to the proposed standards of performance for new EGUs. Because the EPA proposed to find that the BSER for new fossil fuel-fired boilers and IGCC units is only a partial application of CCS, we recognize that there is the potential for such units, if constructed, to obtain additional emission reductions by increasing the level of CCS and outperforming the proposed performance standards. In some cases these incremental emission reductions may represent a cost effective abatement option for states and would provide an incentive for the deployment and advancement of CCS. We invite comment on whether incremental emission reductions from new fossil fuel-fired boilers and IGCC units with CCS, based on exceeding the CAA section 111(b) performance standards for such units, should be allowed as a compliance option to help meet the emission performance level required under a CAA section 111(d) state plan.
Similarly, while the EPA did not propose to establish standards of performance for new NGCC units based on CCS under CAA section 111(b), we recognize that if a new NGCC unit were to be constructed with a CCS system, it could achieve a lower CO
Building block 4 focuses on improving end-use energy efficiency. Another way to reduce the utilization of, and CO
In addition, electricity storage technologies have the potential to enhance emission performance by reducing the need for fossil fuel-fired EGUs to provide generation during periods when intermittent wind and solar generation are unavailable due to natural conditions. States may wish to consider this possibility as they consider options for design of their plans.
The agency requests comment on whether industrial combined heat and power approaches warrant consideration as a potential way to avoid affected EGU emissions, and whether the answer depends on circumstances that depend on the type of CHP in question.
Many of the decisions that states will make while developing compliance approaches are fundamentally state decisions that will have impacts on issues important to the state, including cost to consumers and broader energy policy goals, but will not impact overall emission performance. Some decisions, however, may impact emission performance and exemplify the kinds of decisions and approaches states may be interested in pursuing. In light of the broad latitude that the EPA is seeking to afford the states, including latitude to adopt measures such as those discussed in this subsection, the EPA intends to make additional technical resources available and consider developing guidance for states, should they need such support in exploring and adopting these options. The EPA, in addition, requests comment on whether there are still other areas beyond those discussed above for which it would be useful for the EPA to provide guidance.
Through President Obama's Climate Action Plan, the Administration is working to identify new approaches to protect and restore our forests, as well as other critical landscapes including grasslands and wetlands, in the face of a changing climate. Sustainable forestry and agriculture can improve resiliency to climate change, be part of a national strategy to reduce dependence on fossil fuels, and contribute to climate change mitigation by acting as a “sink” for carbon. The plant growth associated with producing many of the biomass-derived fuels can, to varying degrees for different biomass feedstocks, sequester carbon from the atmosphere. For example, America's forests currently play a critical role in addressing carbon pollution, removing nearly 12 percent of total U.S. greenhouse gas emissions each year. As a result, broadly speaking, burning biomass-derived fuels for energy recovery can yield climate benefits as compared to burning conventional fossil fuels.
Many states have recognized the importance of forests and other lands for climate resilience and mitigation and have developed a variety of different sustainable forestry policies, renewable energy incentives and standards and greenhouse gas accounting procedures. Because of the positive attributes of certain biomass-derived fuels, the EPA also recognizes that biomass-derived fuels can play an important role in CO
To better understand the impacts of using different types of biomass-derived fuels, the EPA is assessing the use of biomass feedstocks for energy recovery by stationary sources and has developed a draft accounting framework that the EPA's Science Advisory Board (SAB) has reviewed. The draft framework concluded that while biomass and other biogenic feedstocks have the potential to reduce the overall level of CO
The EPA is in the process of revising the draft framework and considering next steps, taking into account both the comments provided by the SAB and feedback from stakeholders. The EPA's biogenic CO
In this section, the EPA discusses the relevance to this rule of the EPA regulations implementing the CAA section 111(d)(1) provision “permit[ing] the State in applying a standard of performance to any particular source under a [111(d)] plan . . . to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.”
For the reasons discussed below, the EPA is proposing that, in this case, the flexibility provided in the state plan development process adequately allows for consideration of the remaining useful life of the affected facilities and other source-specific factors and, therefore, that separate application of the remaining useful life provision by states in the course of developing and implementing their CAA section 111(d) plans is unnecessary. The agency is requesting comment on its analysis below of the implications of the EPA's existing regulations interpreting “useful life” and “other factors” for purposes of this rulemaking.
This section addresses the legal background concerning facility-specific considerations and the implications for implementation of these emission guidelines, including state emissions performance goals.
The EPA's 1975 implementing regulations
The reference to “[u]nreasonable cost of control resulting from plant age” implements the statutory provision on remaining useful life. The language concerning plant location, basic process design, physical impossibility of installing controls, and “other factors” addresses facility-specific issues other than remaining useful life that the EPA determined that in some circumstances can affect the reasonableness of a control measure for a particular existing source.
This regulatory provision provides the EPA's default structure for implementing the remaining useful life provision of CAA section 111(d). The opening clause, however, which provides that this provision is applicable “unless otherwise specified in the applicable subpart” makes clear that this structure may not be appropriate in each case and that the EPA has discretion to alter the extent to which states may authorize relaxations to standards of performance that would otherwise apply to a particular source or source category, if appropriate under the circumstances of the specific source category and proposed guidelines.
In general, the EPA notes that the implementing regulation provisions for remaining useful life and other facility-specific factors are relevant for emission guidelines in which the EPA specifies a presumptive standard of performance that must be fully and directly implemented by each individual existing source within a specified source category. Such guidelines are much more like a CAA section 111(b) standard in their form. For example, the EPA emission guidelines for sulfuric acid plants, phosphate fertilizer plants, primary aluminum plants, and Kraft pulp plants specify emission limits for sources.
In these proposed guidelines for state plans to limit CO
Rather, because of the flexibility for states to design their own standards, the states have the ability to address the issues involved with “remaining useful life” and “other factors” in the initial design of those standards, which would occur within the framework of the CAA section 111(d) plan development process. States are free to specify requirements for individual EGUs that are appropriate considering remaining useful life and other facility-specific factors.
Therefore, to the extent that a performance standard that a state may wish to adopt for affected EGUs raises facility-specific issues, the state is free to make adjustments to a particular facility's requirements on facility-specific grounds, so long as any such adjustments are reflected (along with
The EPA also believes that, because of the way the state-specific goals have been developed in these proposed guidelines, remaining useful life and other facility-specific considerations should not affect the determination of a state's rate-based or mass-based emission performance goal or the state's obligation to develop and submit an approvable CAA section 111(d) plan that achieves that goal by the applicable deadline.
Under the proposed guideline, states would have the flexibility to adopt a state plan that relies on emission-reducing requirements that do not require affected EGUs with a short remaining useful life to make major capital expenditures
We also note that a state is not required to achieve the same level of emission reductions with respect to any one building block as assumed in the EPA's BSER analysis. If a state prefers not to attempt to achieve the level of performance estimated by the EPA for a particular building block, it can compensate through over-achievement in another one, or employ other compliance approaches not factored into the state-specific goal at all. The EPA has estimated reasonable rather than maximum possible implementation levels for each building block in order to establish overall state goals that are achievable/while allowing states to take advantage of the flexibility to pursue some building blocks more aggressively, and others less aggressively, than is reflected in the goal computations, according to each state's needs and preferences.
Of the four building blocks considered by the EPA in developing state goals, only the first block, heat rate improvements, involves capital investments at the affected EGUs which, if mandated by a state rule, might give rise to remaining useful life considerations at a particular facility. The other building blocks—re-dispatch among affected sources, addition of new generating capacity, and improvement in end-use energy efficiency—do not generally involve capital investments by the owner/operator at an affected EGU.
In the case of heat rate improvements at affected EGUs, states can choose whether to require a greater or lesser degree of heat rate improvement than the 6 percent improvement assumed in the EPA's proposed BSER determination, either because of the remaining useful life of one or more EGUs, other source-specific factors that the state deemed appropriate to consider, or any other relevant reasons. The agency also notes that any capital expenditures would be much smaller than capital expenditures required for example, for purchase and installation of scrubbers to remove sulfur dioxide; a fleet-wide average cost for heat rate improvements at coal-fired generating units is $100/kW, compared with a typical SO
Remaining useful life and other factors, because of their facility-specific nature, are potentially relevant in determining requirements that are directly applicable to affected EGUs. For all of the reasons above, the agency believes that the issue of remaining useful life will arise infrequently in the development of state plans to limit CO
In this section, we discuss whether state plans may include design, equipment, work practice, or operational standards.
CAA section 111(h)(1) authorizes the Administrator to promulgate “a design, equipment, work practice, or operational standard, or combination thereof,” if in his or her judgment, “it is not feasible to prescribe or enforce a standard of performance.” CAA section 111(h)(2) provides the circumstances under which prescribing or enforcing a standard of performance is “not feasible”: generally, when the pollutant cannot be emitted through a conveyance designed to emit or capture the pollutant, or when there is no practicable measurement methodology for the particular class of sources. Other provisions in section 111(h) further provide that a design, equipment, work practice, or operational standard (i) must “be promulgated in the form of a standard of performance whenever it becomes feasible” to do so,
As noted above, CAA section 111(d) requires that state plans “establish[] standards of performance” as well as “provide[] for the implementation and enforcement of such standards of performance.” CAA section 111(d) is silent as to whether (i) states may include design, equipment, work practice, or operational standards, or (ii) they may include those types of standards, but only under the limited circumstances described in section 111(h) (i.e., when it is “not feasible” to prescribe or enforce a standard of performance). Similarly, section 111(h) applies by its terms when the Administrator is authorized to prescribe standards of performance (which would include rulemaking under CAA section 111(b)), but is silent as to whether it
We invite consideration of the proper interpretation of CAA sections 111(d) and (h), under either
In this section, we discuss why CAA section 111(d) plans may include standards of performance that authorize emissions averaging and trading.
CAA section 111(d) authorizes state plans to include “standards of performance” and measures that implement and enforce those standards of performance. CAA section 111(a)(1) defines a “standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction . . . adequately demonstrated.” CAA section 302 contains a set of definitions that apply “[w]hen used in [the Clean Air Act],” including subsection (l), which provides a separate definition of “standard of performance” as “a requirement of continuous emission reduction. . .”
The EPA proposes that the definition of “standard of performance” is broad enough to incorporate emissions averaging and trading provisions, including both emission rate programs, in which sources may average or trade those rates, and mass emission limit programs, in which sources may buy and sell mass emission allowances (and, under certain circumstances, offsets).
Moreover, although there may be doubt that the definition of “standard of performance” in CAA section 302(l) applies to CAA section 111(d) in light of the fact that the definition of the same term in CAA section 111(a)(1) is more specific, even if the CAA section 302(l) definition does apply, an averaging or trading requirement qualifies as a “continuous emission reduction” because, in the case of a tradable emission rate, the rate is applicable at all times, and, in the case of a tradable mass limit, the source is always under the obligation that its emissions be covered by allowances.
It should be noted that the EPA has promulgated two other CAA section 111(d) rulemakings that authorized state plans to include emissions averaging or trading.
A resource available from the EPA for states pursuing market-based approaches is the EPA's data and experience in support of state trading programs and emissions data collection. For states needing technical assistance with data or operation of market-based programs, existing EPA data systems are a resource that have been used to collect emissions data, track allowances and transfers, and determine compliance for state programs. For example, New Hampshire was part of the Ozone Transport Commission (OTC) trading program but was not included in the NOx SIP Call. Because the state wanted its sources to continue to participate in a state trading program, the EPA operated the emissions trading program for New Hampshire sources, from allocating allowances to compliance determination.
Additionally, as noted elsewhere in this preamble, more than 25 states have mandatory renewable portfolio standards, and other states have voluntary renewable programs and goals. There is considerable diversity among the states in the scope and coverage of these standards, in particular in how renewable resources are defined. At the federal level, the EPA has considered the greenhouse gas implications related to biomass use at stationary sources through several actions, including a call for information from stakeholders and the development and review of the “Accounting Framework for Biogenic CO
As part of the stakeholder outreach process, the EPA asked states what the agency could do to facilitate state plan development and implementation. Some states indicated that they wanted the EPA to create resources to assist with state plan development, especially resources related to accounting for end-use energy efficiency and renewable energy (EE/RE) in state plans. They requested clear methodologies for
As a result of this feedback, in consultation with U.S. Department of Energy and other federal agencies, the EPA has developed a toolbox of decision support resources and is making that available at a dedicated Web site:
For the final rulemaking, the EPA plans to organize resources on the Web site around the following two categories: State plan guidance and state plan decision support. The state plan guidance section will serve as a central repository for the final emission guidelines, regulatory impact analysis, technical support documents, and other supporting materials. The state plan decision support section will include information to help states evaluate different approaches and measures they might consider as they initiate plan development. This section will include, for example, a summary of existing state climate and EE/RE policies and programs,
We note that our inclusion of a measure in the toolbox does not mean that a state plan must include that measure. In fact, inclusion of measures provided at the Web site does not necessarily imply the approvability of an approach or method for use in a state plan. States will need to demonstrate that any measure included in a state plan meets all relevant approvability criteria and adequately addresses elements of the plan components discussed in Section VIII of this preamble.
The EPA solicits comment on this approach and the information currently included, and planned for inclusion, in the Decision Support Toolbox.
The new source review (NSR) program is a preconstruction permitting program that requires major stationary sources of air pollution to obtain permits prior to beginning construction. The requirements of the NSR program apply both to new construction and to modifications of existing major sources. Generally, a source triggers these permitting requirements as a result of a modification when it undertakes a physical or operational change that results in a significant emission increase and a net emissions increase. NSR regulations define what constitutes a significant net emissions increase, and the concept is pollutant-specific. For GHG emissions, the PSD applicability analysis is described in the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 31514, June 3, 2010). As a general matter, a modifying major stationary source would trigger PSD permitting requirements for GHGs if it emits GHGs in excess of 100,000 tons per year (tpy) of carbon dioxide equivalents (CO
As part of its CAA section 111(d) plan, a state may impose requirements that require an affected EGU to undertake a physical or operational change to improve the unit's efficiency that results in an increase in the unit's dispatch and an increase in the unit's annual emissions. If the emissions increase associated with the unit's changes exceeds the thresholds in the NSR regulations discussed above for one or more regulated NSR pollutants, including the netting analysis, the changes would trigger NSR.
While there may be instances in which an NSR permit would be required, we expect those situations to be few. As previously discussed in this preamble, states have considerable flexibility in selecting varied measures as they develop their plans to meet the goals of the emissions guidelines. One of these flexibilities is the ability of the state to establish the standards of performance in their CAA section 111(d) plans in such a way so that their affected sources, in complying with those standards, in fact would not have emissions increases that trigger NSR. To achieve this, the state would need to conduct an analysis consistent with the NSR regulatory requirements that supports its determination that as long as affected sources comply with the standards of performance in their CAA section 111(d) plan, the source's emissions would not increase in a way that trigger NSR requirements.
For example, a state could decide to adjust its demand side measures or increase reliance on renewable energy as a way of reducing the future emissions of an affected source initially predicted (without such alterations) to increase its emissions as a result of a CAA section 111(d) plan requirement. In other words, a state plan's incorporation of expanded use of cleaner generation or demand-side measures could yield the result that units that would otherwise be projected to trigger NSR through a physical change that might result in increased dispatch would not, in fact, increase their emissions, due to reduced demand for their operation. The state could also, as part of its CAA section 111(d) plan, develop conditions for a source expected to trigger NSR that would limit the unit's ability to move up in the dispatch enough to result in a significant net emissions increase that would trigger NSR (effectively establishing a synthetic minor limit).
We request comment on whether, with adequate record support, the state plan could include a provision, based on underlying analysis, stating that an affected source that complies with its applicable standard would be treated as not increasing its emissions, and if so, whether such a provision would mean that, as a matter of law, the source's actions to comply with its standard
As a result of such flexibility and anticipated state involvement, we expect that a limited number of affected sources would trigger NSR when states implement their plans.
The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; January 8, 2014) explained that regulating GHGs for the first time under section 111 of the CAA would make GHGs “regulated air pollutants” for the first time under the operating permit regulations of 40 CFR parts 70 and 71. This would result in GHGs becoming “fee pollutants” in certain state part 70 permit programs and in the EPA's part 71 permit program, thus requiring the collection of fees for GHG emissions in these programs. Where title V fees would be required for GHGs, they would typically be charged at the same rate ($ per ton of pollutant) as all other fee pollutants. This would likely result in excessive and unnecessary fees being charged to subject sources. To avoid this situation, we proposed to exempt GHGs from the fee rates in effect for other fee pollutants, while proposing an alternative fee that would be much lower than the fee charged to other fee pollutants, yet sufficient to cover the costs of addressing GHGs in operating permits.
This title V fee issue is a one-time occurrence resulting from the promulgation of the first CAA section 111 standard to regulate GHGs (the EGU NSPS for new sources) and is not an issue for any other subsequent CAA section 111 regulations, so there is no need to address any title V fee issues in this proposal. Thus, we are not re-visiting these title V fee issues in this proposal, and we are not proposing any additional revisions to any title V regulations as part of this action.
The title V regulations require each permit to include emission limitations and standards, including operational requirements and limitations that assure compliance with all applicable requirements. Requirements resulting from this rule that are imposed on affected EGUs or any other potentially affected entities that have title V operating permits are applicable requirements under the title V regulations and would need to be incorporated into the source's title V permit in accordance with the schedule established in the title V regulations. For example, if the permit has a remaining life of three years or more, a permit reopening to incorporate the newly applicable requirement shall be completed no later than 18 months after promulgation of the applicable requirement. If the permit has a remaining life of less than three years, the newly applicable requirement must be incorporated at permit renewal.
Existing fossil fuel-fired EGUs, such as those covered in this proposal, are or will be potentially impacted by several other recently finalized or proposed EPA rules.
The EPA is closely monitoring MATS compliance and finds that the industry is making substantial progress. Plant owners are moving proactively to install controls that will achieve the MATS performance standards. Certain units, especially those that operate infrequently, may be considered not worth investing in given today's electricity market, and those are closing.
Existing sources subject to the MATS rule are given until April 16, 2015 to comply with the rule's requirements. The final MATS rule provided a foundation on which states and other permitting authorities could rely in granting an additional, fourth year for compliance provided for by the CAA. States report that these fourth year extensions are being granted. In addition, the EPA issued an enforcement policy that provides a clear pathway for reliability-critical units to receive an administrative order that includes a compliance schedule of up to an additional year, if it is needed to ensure electricity reliability.
On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (33 U.S.C. 1326(b)) (referred to hereinafter as the 316(b) rule).
The EPA is also reviewing public comments and working to finalize two proposed rules which will also impact
On June 7, 2013 (78 FR 34432), the EPA proposed the SE ELG rule to strengthen the controls on discharges from certain steam electric power plants by revising technology-based effluent limitations guidelines and standards for the steam electric power generating point source category. The current regulations, which were last updated in 1982, do not adequately address the toxic pollutants discharged from the electric power industry, nor have they kept pace with process changes that have occurred over the last three decades. Existing steam electric power plants currently contribute 50-60 percent of all toxic pollutants discharged to surface waters by all industrial categories regulated in the United States under the CWA. Furthermore, power plant discharges to surface waters are expected to increase as pollutants are increasingly captured by air pollution controls and transferred to wastewater discharges. This proposed regulation, which includes new requirements for both existing and new generating units, would reduce the amount of toxic metals and other pollutants discharged to surface waters from power plants.
On June 21, 2010 (75 FR 35128), the EPA proposed the CCR rule, which co-proposed two approaches to regulating the disposal of coal combustion residuals (CCRs) generated by electric utilities and independent power producers. CCRs are residues from the combustion of coal in steam electric power plants and include materials such as coal ash (fly ash and bottom ash) and flue gas desulfurization (FGD) wastes. Under one proposed approach, the EPA would list these residuals as “special wastes,” when destined for disposal in landfills or surface impoundments, and would apply the existing regulatory requirements established under Subtitle C of RCRA to such wastes. Under the second proposed approach, the EPA would establish new regulations applicable specifically to CCRs under subtitle D of RCRA, the section of the statute applicable to solid (i.e., non-hazardous) wastes. Under both approaches, CCRs that are beneficially used would remain exempt under the Bevill exclusion.
The EPA recognizes the importance of assuring that each of the rules described above can achieve its intended environmental objectives in a commonsense, cost-effective manner, consistent with underlying statutory requirements, and while assuring a reliable power system. Executive Order (EO) 13563, “Improving Regulation and Regulatory Review,” issued on January 18, 2011, states that “[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote . . . coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation.” Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the industry, reliability and cost that these various rulemakings can have.
As discussed in Sections VII and VIII of this preamble, the EPA is proposing to give states broad flexibility in developing approvable plans under CAA section 111(d), including the ability to adopt rate-based or mass-based emission performance goals, and to rely on a wide variety of CO
The EPA is also endeavoring to enable EGUs to comply with applicable obligations under other power sector rules as efficiently as possible (e.g., by facilitating their ability to coordinate planning and investment decisions with respect to those rules) and, where possible, implement integrated compliance strategies. For example, in the proposed SE ELG rule, the EPA describes its current thinking on how it might effectively harmonize the potential requirements of that rule with the requirements of the final CCR rule, to the extent that both rules may regulate or affect the disposal of coal combustion wastes to and from surface impoundments at power plants.
In addition to the power sector rules discussed above, the development of SIPs for criteria pollutants (PM
On June 6, 2013, the EPA proposed an implementation rule for the 2008 ozone National Ambient Air Quality Standards (NAAQS), to provide rules and guidance to states on the development of approvable state implementation plans (SIPs), including SIPs under CAA section 110 (infrastructure SIPs) and section 182 (ozone nonattainment SIPs). This rule addresses the statutory requirements for areas that the EPA has designated as nonattainment for the 2008 ozone standard. The agency is currently working to finalize that rule. The EPA is also working on a proposed transport rule that would identify the obligations of upwind states that contribute to those downwind state ozone nonattainment areas. This rule is scheduled for proposal in 2014 and to be finalized by 2015.
The EPA is developing a proposed implementation rule to provide guidance to states on the development of SIPs for the 2012 PM
The SO
The EPA requires SIP updates every 10 years for regional haze, as required by the EPA's Regional Haze Rule which was promulgated in 1999. The next 10-year SIP revision for regional haze, covering the time period through 2028, is due from each state by July 2018. Each SIP must provide for reasonable progress towards visibility improvement in protected scenic areas.
The development of these SIPs may, where applicable, have significant implications for existing fossil fuel-fired EGUs, as well as for the states that are responsible for developing them. The timeframes for submittal of SIPs for the various programs and the timeframes we are proposing for submittal of the CAA section 111(d) state plans will allow considerable time for coordination by states in the development of their respective plans. The EPA is willing to work with states to assist them in coordinating their efforts across these planning processes. The EPA believes that CAA section 111(d) efforts and actions will tend to contribute to overall air quality improvements and thus should be complementary to criteria pollutant and regional haze SIP efforts.
In light of the broad flexibilities we are proposing in this action, we believe that states will have ample opportunity to design CAA section 111(d) plans that use innovative, cost-effective regulatory strategies and that spark investment and innovation across a wide variety of clean energy technologies. We also believe that the broad flexibilities we are proposing in this action will enable states and affected EGUs to build on their longstanding, successful records of complying with multiple CAA, CWA, and other environmental requirements, while assuring an adequate, affordable, and reliable supply of electricity.
The EPA anticipates significant emission reductions under the proposed guidelines for the power sector. CO
The reductions in these tables do not account for reductions in hazardous air pollutants (HAPs) that may occur as a result of this rule. For instance, the fine particulate reductions presented above do not reflect all of the reductions in many heavy metal particulates.
Though the EPA has determined that the 4-building block approach is the BSER, we did analyze the impacts of both a combination of building blocks 1 and 2 and the combination of all four building blocks. The analysis indicates that the combined strategies of heat rate improvements (building block 1) and re-dispatch (building block 2) would result in overall CO
The EPA projects that the annual incremental compliance cost for the building block 1 and 2 approach is estimated to be $3.2 to $4.4 billion in 2020 and $6.8 to $9.8 billion (2011$) in 2030, excluding the costs associated with monitoring, reporting, and recordkeeping (MRR). This compares to costs excluding MRR of $5.4 to $7.4 billion in 2020 and $7.3 to $8.8 billion in 2030 for the proposed Option 1 (2011$) as discussed in Section X.E of this preamble.
The total combined climate benefits and health co-benefits for the building block 1 and 2 approach are estimated to be $21 to $40 billion in 2020 and $32 to $63 billion in 2030 (2011$ at a 3-percent discount rate [model average]). The net benefits are estimated to be $18 to $36 billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-percent discount rate [model average]). For the purposes of this summary, we list the climate benefits associated with the marginal value of the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. These building block 1 and 2 benefit estimates compare to combined climate benefits and health co-benefits of $33 to $57 billion in 2020 and $55 to $93 billion in 2030 (2011$ at a 3-percent discount rate [model average]) for the proposed Option 1. Net benefits are estimated to be $27 to $50 billion in 2020 and $48 to $84 billion in 2030 (2011$ at a 3-percent discount rate [model average]) as discussed in Section X.G. and XI.A of this preamble.
Consistent with the requirements of section 7(a)(2) of the Endangered Species Act (ESA), the EPA has also considered the effects of this proposed rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed endangered or threatened species or designated critical habitat. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the U.S. Fish and Wildlife Service (FWS) and/or the National Marine Fisheries Service, to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of federally listed endangered or threatened species or result in the destruction or adverse modification of designated critical habitat of such species. 16 U.S.C. 1536(a)(2). Under relevant implementing regulations, section 7(a)(2) applies only to actions where there is discretionary federal involvement or control. 50 CFR 402.03. Further, under the regulations consultation is required only for actions that “may affect” listed species or designated critical habitat. 50 CFR § 402.14. Consultation is not required where the action has no effect on such species or habitat. Under this standard, it is the federal agency taking the action that evaluates the action and determines whether consultation is required.
The EPA has considered the effects of this proposed rule and has reviewed applicable ESA regulations, case law, and guidance to determine what, if any, impact there may be to listed species or designated critical habitat for purposes of section 7(a)(2) consultation. The EPA notes that the projected environmental effects of this proposal are positive: reductions in overall GHG emissions, and reductions in PM and ozone-precursor emissions (SO
With regard to non-GHG air emissions, the EPA is also projecting substantial reductions of SO
Moreover, there are substantial questions as to whether any potential for relevant effects results from any element of the proposed rule or would result instead from the separate actions of States establishing standards of performance for existing sources and implementing and enforcing those standards.
The proposed guidelines have important energy market implications. Under Option 1, average nationwide retail electricity prices are projected to increase by roughly 6 to 7 percent in 2020 relative to the base case, and by roughly 3 percent in 2030 (contiguous U.S.). Average monthly electricity bills are anticipated to increase by roughly 3 percent in 2020, but decline by approximately 9 percent by 2030. This is a result of the increasing penetration of demand-side programs that more than offset increased prices to end users by their expected savings from reduced electricity use.
The average delivered coal price to the power sector is projected to decrease by 16 to 17 percent in 2020 and roughly 18 percent in 2030, relative to the base case for Option 1. The EPA also projects that electric power sector-delivered natural gas prices will increase by 9 to 12 percent in 2020, with negligible changes in 2030. Natural gas use for electricity generation will increase by as much as 1.2 trillion cubic feet (TCF) in 2020 relative to the base case, and then begin to decline over time.
These figures reflect the EPA's illustrative modeling that presumes policies that lead to dispatch changes in 2020 and growing use of energy efficiency and renewable electricity generation out to 2029. If states make different policy choices, impacts could be different. For instance, if states implement renewable and/or energy efficiency policies on a more aggressive time-frame, impacts on natural gas and electricity prices would likely be less. Implementation of other measures not included in the EPA's BSER calculation or compliance modeling, such as nuclear uprates, transmission system improvements, use of energy storage technologies or retrofit CCS, could also mitigate gas price and/or electricity price impacts.
The EPA projects coal production for use by the power sector, a large component of total coal production, will decline by roughly 25 to 27 percent in 2020 from base case levels. The use of coal by the power sector will decrease roughly 30 to 32 percent in 2030. Renewable energy capacity is anticipated to increase by roughly 12 GW in 2020 and by 9 GW in 2030 under Option 1. Energy market impacts from the guidelines are discussed more extensively in the RIA found in the docket for this rulemaking.
The compliance costs of this proposed action are represented in this analysis as the change in electric power generation costs between the base case and the proposed rule in which states pursue a distinct set of strategies beyond the strategies taken in the base case to meet the terms of the EGU GHG emission guidelines, and include cost estimates for demand-side energy efficiency. The compliance assumptions—and, therefore, the projected compliance costs—set forth in this analysis are illustrative in nature and do not represent the full suite of compliance flexibilities states may ultimately pursue. These illustrative compliance scenarios are designed to reflect, to the extent possible, the scope and the nature of the proposed guidelines. However, there is considerable uncertainty with regards to the precise measures that states will adopt to meet the proposed requirements, because there are considerable flexibilities afforded to the states in developing their state plans.
The EPA projects that the annual incremental compliance cost of Option 1 is estimated to be between $5.5 and $7.5 billion in 2020 and between $7.3
The proposed standards are projected to result in certain changes to power system operation as a result of the application of state emission rate goals. Overall, we project dispatch changes, changes to fossil fuel and retail electricity prices, and some additional coal retirements. Average electric power sector-delivered natural gas prices are projected to increase by roughly 9 to 12 percent in 2020 in Option 1, with negligible changes by 2030. Under Option 2, electric power sector natural gas prices are projected to increase by roughly 8 percent in 2020, on an average nationwide basis, and increase by 1 percent or less in 2025. The average delivered coal price to the power sector is projected to decrease by 16 to 17 percent in 2020 under Option 1, and decrease by roughly 14 percent under Option 2, on a nationwide average basis. Retail electricity prices are projected to increase 6 to 7 percent under Option 1 and increase by roughly 4 percent under Option 2, both in 2020 and on an average basis across the contiguous U.S. By 2030 under Option 1, electricity prices are projected to increase by about 3 percent. Under Option 1, the EPA projects 46 to 50 GW of additional coal-fired generation may be uneconomic to maintain and may be removed from operation by 2030. The EPA projects that under Option 2, 30 to 33 GW of additional coal-fired generation may be uneconomic to maintain and may be removed from operation by 2025.
It is important to note that the EPA's modeling does not necessarily account for all of the factors that may influence business decisions regarding future coal fired capacity. By 2025, the average age of the coal-fired fleet will be 49 years old and twenty percent of the fleet will be more than 60 years old. Many power companies already factor a carbon price into their long term capacity planning that would further influence business decisions to replace these aging assets with modern, and significantly cleaner generation.
The compliance modeling done to support the proposal assumes that overall electric demand will decrease significantly, as states ramp up programs that result in lower overall demand. End-use energy efficiency levels increase such that they achieve about an 11 percent reduction on overall electricity demand levels in 2030 for Option 1, and a reduction in overall electricity demand of approximately 6 percent reduction in 2025 for Option 2. In response, there are anticipated to be notable changes to costs, prices, and electricity generation in the power sector as more end-use efficiency is realized.
Changes in price or demand for electricity, natural gas, coal, can impact markets for goods and services produced by sectors that use these energy inputs in the production process or supply those sectors. Changes in cost of production may result in changes in price, changes in quantity produced, and changes in profitability of firms affected. The EPA recognizes that these guidelines provide significant flexibilities and states implementing the guidelines may choose to mitigate impacts to some markets outside the EGU sector. Similarly, demand for new generation or energy efficiency can result in shifts in production and profitability for firms that supply those goods and services, and the guidelines provide flexibility for states that may want to enhance demand for goods and services from those sectors.
Executive Order 13563 directs federal agencies to consider the effect of regulations on job creation and employment. According to the Executive Order, “our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation. It must be based on the best available science.” (Executive Order 13563, 2011) Although standard benefit-cost analyses have not typically included a separate analysis of regulation-induced employment impacts, we typically conduct employment analyses. During periods of sustained high unemployment, employment impacts are of particular concern and questions may arise about their existence and magnitude.
States have the responsibility and flexibility to implement policies and practices for compliance with Proposed Electric Generating Unit Greenhouse Gas Existing Source Guidelines. Quantifying the associated employment impacts is complicated by the wide range of approaches that States may use. As such, the EPA's employment analysis includes projected employment impacts associated with illustrative compliance scenarios for these guidelines for the electric power industry, coal and natural gas production, and demand-side energy efficiency activities. These projections are derived, in part, from a detailed model of the electricity production sector used for this regulatory analysis, and U.S government data on employment and labor productivity. In the electricity, coal, and natural gas sectors, the EPA estimates that these guidelines could have an employment impact of roughly 25,900 to 28,000 job-years increase in 2020 for Option 1, state to regional compliance approach, respectively. For Option 2, the state and regional compliance approach estimates are 26,700 to 29,800 job-years increase in 2020. Demand-side energy efficiency employment impacts are approximately an increase of 78,800 jobs in 2020 for Option 1 and of 57,000 jobs for Option 2. By its nature, energy efficiency reduces overall demand for electric power. The EPA recognizes as more efficiency is built into the U.S. power system over time, lower fuel requirements may lead to fewer jobs in the coal and natural gas extraction sectors, as well as in EGU construction and operation than would otherwise have been expected. The EPA also recognizes the fact that, in many cases, employment gains and losses that might be attributable to this rule would be expected to affect different sets of people. Moreover, workers who lose jobs in these sectors may find employment elsewhere just as workers employed in new jobs in these sectors may have been previously employed elsewhere. Therefore, the employment estimates reported in these sectors may include workers previously employed elsewhere. This analysis also does not capture potential economy-wide impacts due to changes in prices (of fuel, electricity, labor, etc.). For these reasons, the numbers reported here
Implementing the proposed standards will generate benefits by reducing emissions of CO
The EPA has used the social cost of carbon (SCC) estimates presented in the 2013
The EPA and other agencies have sought public comment on the SCC estimates as part of various rulemakings. In addition, OMB's Office of Information and Regulatory Affairs recently sought public comment on the approach used to develop the estimates. The comment period ended on February 26, 2014, and OMB is reviewing the comments received.
The four SCC estimates, updated in 2013, are as follows: $13, $46, $68, and $137 per metric ton of CO
The 2010 SCC TSD noted a number of limitations to the SCC analysis, including the incomplete way in which the integrated assessment models capture catastrophic and non-catastrophic impacts, their incomplete treatment of adaptation and
The health co-benefits estimates represent the total monetized human health benefits for populations exposed to reduced PM
These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. Even though we assume that all fine particles have equivalent health effects, the benefit-per-ton estimates vary between precursors depending on the location and magnitude of their impact on PM
It is important to note that the magnitude of the PM
In this analysis, the EPA assumes that the health impact function for fine particles is without a threshold. This is based on the conclusions of EPA's
In general, we are more confident in the magnitude of the risks we estimate from simulated PM
For this analysis, policy-specific air quality data are not available,
Every benefit analysis examining the potential effects of a change in environmental protection requirements is limited, to some extent, by data gaps, model capabilities (such as geographic coverage) and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Despite these uncertainties, we believe the air quality co-benefit analysis for this rule provides a reasonable indication of the expected health benefits of the air pollution emission reductions for the illustrative compliance options for the proposed standards under a set of reasonable assumptions. This analysis does not include the type of detailed uncertainty assessment found in the 2012 PM
We note that the monetized co-benefits estimates shown here do not include several important benefit categories, including exposure to SO
For more information on the benefits analysis, please refer to the RIA for this rule, which is available in the rulemaking docket.
Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. The $100 million threshold can be triggered by either costs or benefits, or a combination of them. Accordingly, the EPA submitted this action to OMB for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and any changes made in response to OMB recommendations have been documented in the docket for this action.
The EPA also prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in the RIA for this proposed rule. A copy of the analysis is available in the docket for this action.
Consistent with EO 12866 and EO 13563, the EPA estimated the costs and benefits for illustrative compliance approaches of implementing the proposed guidelines. This proposal sets goals to reduce CO
The EPA has used the social cost of carbon estimates presented in the 2013
For Option 1 in 2030 assuming a regional compliance approach, the EPA estimates this proposal will yield monetized climate benefits (in 2011$) of approximately $30 billion (3 percent, model average). The air pollution health co-benefits in 2030 are estimated to be $25 billion to $59 billion (2011$) for a 3 percent discount rate and $23 billion to $54 billion (2011$) for a 7 percent discount rate. The annual illustrative compliance costs estimated using IPM, inclusive of a demand-side energy efficiency program and participant costs and MRR costs, are approximately $7.3 billion (2011$) in 2030. The quantified net benefits (the difference between monetized benefits and costs) in 2030 are estimated to be $48 billion to $82 billion (2011$) using a 3 percent discount rate (model average). The EPA estimates that this proposal will yield monetized climate benefits (in 2011$) of approximately $31 billion (3 percent, model average) for Option 1 state compliance approach in 2030. The air pollution health co-benefits in 2030 are estimated to be $27 billion to $62 billion (2011$) for a 3 percent discount rate and $24 billion to $56 billion (2011$) for a 7 percent discount rate. The annual illustrative compliance costs estimated using IPM, inclusive of demand side energy efficiency program and participant costs and MRR costs, are approximately $8.8 billion (2011$) in 2030. The quantified net benefits (the difference between monetized benefits and costs) in 2030 are estimated to be $49 billion to $84 billion (2011$) using a 3 percent discount rate (model average) assuming a state compliance approach. Based upon the foregoing discussion, it remains clear that the benefits of the proposal Option 1 are substantial and far exceed the costs.
The estimated costs and benefits for the regulatory alternative—Option 2 regional and state compliance approaches are shown in Tables 20 and 21. As these tables reflect, net benefits in 2020 are estimated to be $22 to $40 billion (3 percent discount rate) and $21 to $37 billion (7 percent discount rate) for Option 2 assuming regional compliance. These Option 2 net benefit estimates become $22 to $40 billion (3 percent discount rate) and $20 to $37 billion (7 percent discount rate) with the state compliance approach. In 2025, net benefits are estimated to be $31 billion to $54 billion (3 percent discount rate) and $29 billion to $50 billion (7 percent discount rate) assuming a regional compliance approach and $31 billion to $55 billion (3 percent discount rate) and $29 billion to $51 billion (7 percent discount rate) assuming a state compliance approach.
The EPA could not monetize important benefits of proposed Option 1 and regulatory alternative Option 2. Unquantified benefits include climate benefits from reducing emissions of non-CO
The analysis done in support of this proposal shows that the emission reductions, benefits, and costs for the illustrative compliance approaches for the proposed Option 1 (and regulatory alternative Option 2) are larger if states choose to comply on an individual basis, compared to the illustrative regional compliance approach. The regional approach allows for more flexibility across states, which results in slightly fewer emission reductions and
In evaluating the impacts of the proposed guidelines, we analyzed a number of uncertainties, for example evaluating different potential spatial approaches to state compliance (i.e., state and regional) and in the estimated benefits of reducing carbon dioxide and other air pollutants. For a further discussion of key evaluations of uncertainty in the regulatory analyses for this proposed rulemaking, see the RIA included in the docket.
The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the
The information collection requirements are based on the recordkeeping and reporting burden associated with developing, implementing, and enforcing a state plan to limit CO
The annual burden for this collection of information for the states (averaged over the first 3 years following promulgation of this proposed action) is estimated to be a range of 316,217 hours at a total annual labor cost of $22,381,044, to 633,001 hours at a total annual labor cost of $44,802,243. The lower bound estimate reflects the assumption that some states already have energy efficiency and renewable energy programs in place. The higher bound estimate reflects the assumption that no states have energy efficiency and renewable energy programs in place. The total annual burden for the federal government (averaged over the first 3 years following promulgation of this proposed action) is estimated to be 53,300 hours at a total annual labor cost of $2,958,005. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information.
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. The OMB control numbers for the EPA's regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
To comment on the agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID Number EPA-HQ-OAR-2013-0602. Submit any comments related to the ICR to the EPA and to OMB. See the
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small entities, small entity is defined as:
(1) A small business that is defined by the SBA's regulations at 13 CFR 121.201 (for the electric power generation industry, the small business size standard is an ultimate parent entity with less than 750 employees. The NAICS codes for the affected industry are in Table 22 below);
(2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities.
The proposed rule will not impose any requirements on small entities. Specifically, emission guidelines
Nevertheless, the EPA is aware that there is substantial interest in the proposed rule among small entities (municipal and rural electric cooperatives). As detailed in Section III.A of this preamble, the EPA has conducted an unprecedented amount of stakeholder outreach on setting emission guidelines for existing EGUs. While formulating the provisions of the proposed rule, the EPA considered the input provided over the course of the stakeholder outreach. Section III.B of this preamble describes the key messages from stakeholders. In addition, as described in the RFA section of the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1499-1500, January 8, 2014), the EPA conducted outreach to representatives of small entities while formulating the provisions of the proposed standards. Although only new EGUs would be affected by those proposed standards, the outreach regarded planned actions for new and existing sources. We invite comments on all aspects of the proposal and its impacts, including potential impacts on small entities.
This proposed action does not contain a federal mandate that may result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or the private sector in any one year. Specifically, the emission guidelines proposed under CAA section 111(d) do not impose any direct compliance requirements on regulated entities, apart from the requirement for states to develop state plans. The burden for states to develop state plans in the 3-year period following promulgation of the rule was estimated and is listed in Section IX B., above, but this burden is estimated to be below $100 million in any one year. Thus, this proposed rule is not subject to the requirements of section 202 or section 205 of the Unfunded Mandates Reform Act (UMRA).
This proposed rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.
In light of the interest among governmental entities, the EPA initiated consultations with governmental entities while formulating the provisions of the proposed standards for new EGUs. Although only new EGUs would be affected by those proposed standards, the outreach regarded planned actions for new and existing sources. As described in the UMRA discussion in the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1500-1501, January 8, 2014), the EPA consulted with the following 10 national organizations representing state and local elected officials: (1) National Governors Association; (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, 8) National Association of Towns and Townships, (9) County Executives of America, and 10) Environmental Council of States. On February 26, 2014, the EPA re-engaged with those governmental entities to provide a pre-proposal update on the emission guidelines for existing EGUs and emission standards for modified and reconstructed EGUs.
While formulating the provisions of these proposed emission guidelines, the EPA also considered the input provided over the course of the extensive stakeholder outreach conducted by the EPA (see Sections III.A. and III.B. of this preamble).
Under Executive Order 13132, the EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by state and local governments, or the EPA consults with state and local officials early in the process of developing the proposed action.
The EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay those costs. As discussed in the Supporting Statement found in the docket for this rulemaking, the development of state plans will entail many hours of staff time to develop and coordinate programs for compliance with the proposed rule, as well as time to work with state legislatures as appropriate, and develop a plan submittal.
The EPA consulted with state and local officials early in the process of developing the proposed action to permit them to have meaningful and timely input into its development. As described in the Federalism discussion in the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1501, January 8, 2014), the EPA consulted with state and local officials in the process of developing the proposed standards for newly constructed EGUs. This outreach regarded planned actions for new, reconstructed, modified and existing sources. The EPA invited the following 10 national organizations representing state and local elected officials to a meeting on April 12, 2011, in Washington DC: (1) National Governors Association; (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. On February 26, 2014, the EPA re-engaged with those governmental entities to provide a pre-proposal update on the emission guidelines for existing EGUs and emission standards for modified and reconstructed EGUs. In addition, extensive stakeholder outreach conducted by the EPA allowed state leaders, including governors, environmental commissioners, energy officers, public utility commissioners, and air directors, opportunities to engage with EPA officials and provide input regarding reducing carbon pollution from power plants.
A detailed Federalism Summary Impact Statement (FSIS) describing the
This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It would not impose substantial direct compliance costs on tribal governments that have affected EGUs located in their area of Indian country. Tribes are not required to, but may, develop or adopt CAA programs. Tribes are not required to develop plans to implement the guidelines under CAA section 111(d) for affected EGUs. To the extent that a tribal government seeks and attains treatment in a manner similar to a state (TAS) status for that purpose and is delegated authority for air quality planning purposes, these proposed emission guidelines would require that planning requirements be met and emission management implementation plans be executed by the tribes. The EPA is aware of three coal-fired EGUs and one natural gas-fired EGU located in Indian country but is not aware of any affected EGUs that are owned or operated by tribal entities. The EPA notes that this proposal does not directly impose specific requirements on EGU sources, including those located in Indian country, such as the three coal-fired EGUs and one natural gas-fired EGU, but provides guidance to any tribe with delegated authority to address CO
The EPA conducted outreach to tribal environmental staff and offered consultation with tribal officials in developing this action. Because the EPA is aware of tribal interest in this proposed rule, prior to the April 13, 2012 proposal (77 FR 22392-22441), the EPA offered consultation with tribal officials early in the process of developing the proposed regulation to permit them to have meaningful and timely input into its development. The EPA's consultation regarded planned actions for new and existing sources. In addition, on April 15, 2014, prior to proposal, the EPA met with Navajo Energy Development Group officials. For this proposed action for existing EGUs, a tribe that has one or more affected EGUs located in its area of Indian country
Consultation letters were sent to 584 tribal leaders. The letters provided information regarding the EPA's development of both the NSPS and emission guidelines for fossil fuel-fired EGUs and offered consultation. No tribes have requested consultation. Tribes were invited to participate in the national informational webinar held August 27, 2013. In addition, a consultation/outreach meeting was held on September 9, 2013, with tribal representatives from some of the 584 tribes. The EPA also met with tribal environmental staff via National Tribal Air Association teleconferences on July 25, 2013, and December 19, 2013. In those teleconferences, the EPA provided background information on the GHG emission guidelines to be developed and a summary of issues being explored by the agency. Tribes have expressed varied points of view. Some tribes raised concerns about the impacts of the regulations on EGUs and the subsequent impact on jobs and revenue for their tribes. Other tribes expressed concern about the impact the regulations would have on the cost of water to their communities as a result of increased costs to the EGU that provide energy to transport the water to the tribes. Other tribes raised concerns about the impacts of climate change on their communities, resources, life ways and hunting and treaty rights. The tribes were also interested in the scope of the guidelines being considered by the agency (e.g., over what time period, relationship to state and multi-state plans) and how tribes will participate in these planning activities. In addition, the EPA held a series of listening sessions prior to development of this proposed action. In 2013, tribes participated in a session with the state agencies, as well as a separate session with tribes.
During the public comment period for this proposal, the EPA will hold meetings with tribal environmental staff to inform them of the content of this proposal, as well as offer further consultation with tribal elected officials where it is appropriate. We specifically solicit comment from tribal officials on this proposed rule.
The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to EO 13045 because it does not involve decisions on environmental health or safety risks that may disproportionately affect children. The EPA believes that the CO
Executive Order 13211 (66 FR 28355; May 22, 2001) requires the EPA to prepare and submit a Statement of Energy Effects to the Administrator of the Office of Information and Regulatory Affairs, OMB, for actions identified as “significant energy actions.” This action, which is a significant regulatory action under EO 12866, is likely to have a significant effect on the supply, distribution, or use of energy. We have prepared a Statement of Energy Effects for this action as follows. We estimate a 4 to 7 percent increase in retail electricity prices, on average, across the contiguous U.S. in 2020, and a 16 to 22 percent reduction in coal-fired electricity generation as a result of this rule. The EPA projects that electric power sector delivered natural gas prices will increase by about 8 to 12 percent in 2020. For more information on the estimated energy effects, please refer to the economic impact analysis for this proposal. The analysis is available in the RIA, which is in the public docket.
Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the EPA to use Voluntary Census Standards (VCS) in its regulatory and procurement activities unless to do so would be inconsistent with applicable law or
The EPA welcomes comments on this aspect of the proposed rulemaking and specifically invites the public to identify potentially-applicable VCS and to explain why such standards should be used in this action.
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S.
Section II.A of this preamble summarizes the public health and welfare impacts from GHG emissions that were detailed in the 2009 Endangerment Finding under CAA section 202(a)(1).
Strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies, summarized in the record for the Endangerment Finding. Their conclusions include that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those on established reservations that are restricted to reservation boundaries and therefore have limited relocation options. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are likely to experience disruptive impacts, including shifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations.
This proposed rule would limit GHG emissions by establishing CO
While there will be many locations with improved air quality for PM
As we noted in the NSR discussion in this preamble, as part of a state's CAA section 111(d) plan, the state may require an affected EGU to undertake a physical or operational changes to improve the unit's efficiency that result in an increase in the unit's dispatch and an increase in the unit's annual emissions of GHGs and/or other regulated pollutants. A state can take steps to avoid increased utilization of particular EGUs and thus avoid any significant increases in emissions including emissions of other regulated pollutants whose environmental effects would be more localized around the affected EGU. To the extent that states take this path, there would be no new environmental justice concerns in the areas near such EGUs. For any EGUs that make modifications that do trigger NSR permitting, the applicable local, state, or federal permitting program will ensure that there are no new NAAQS violations and that no existing NAAQS violations are made worse. For those EGUs in a permitting situation for which the EPA is the permit reviewing authority, the EPA will consider environmental justice issues as required by Executive Order 12898.
In addition to some EGUs possibly being required by a state to make modifications for increased energy efficiency, another effect of the proposed CO
In order to provide opportunities for meaningful involvement early on in the rule making process, the EPA has hosted webinars and conference calls on August 27, 2013, and September 9, 2013, on the proposed rule specifically for environmental justice communities and has taken all comments and suggestions into consideration in the design of the emission guidelines.
The public is invited to submit comments or identify peer-reviewed studies and data that assess effects of exposure to the pollutants addressed by this proposal.
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(V) of the CAA, as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(V)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, part 60 of the Code of the Federal Regulations is proposed to be amended as follows:
42 U.S.C. 7401
(b) After receipt of a plan or plan revision, the Administrator will propose the plan or revision for approval or disapproval. The Administrator will, within four months after the date required for submission of a plan or plan revision, approve or disapprove such plan or revision or each portion thereof, except as provided in § 60.5715.
This subpart establishes emission guidelines and approval criteria for state plans that establish emission standards limiting the control of greenhouse gas emissions from an affected steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected EGU. These emission guidelines are developed in accordance with sections 111(d) of the Clean Air Act and subpart B of this part. To the extent any requirement of this subpart is inconsistent with the requirements of subparts A or B of this part, the requirements of this subpart will apply.
(a) The pollutants regulated by this subpart are greenhouse gases.
(b) The greenhouse gas regulated by this subpart is carbon dioxide (CO
If you are the Administrator of an air quality program in a state with one or more affected EGUs that commenced construction on or before January 8, 2014, you must submit a state plan to the U.S. Environmental Protection Agency (EPA) that implements the emission guidelines contained in this subpart. You must submit a negative declaration letter in place of the state plan if there are no affected EGUs for which construction commenced on or before January 8, 2014 in your state.
The EPA will review your state plan according to § 60.27 except that under § 60.27(b) the Administrator will have twelve months after the date required for submission of a plan or plan revision to approve or disapprove such plan or revision or each portion thereof. If you submit a request for extension under § 60.5760(a) in lieu of a complete state plan the EPA will follow the procedure in § 60.5760(b).
If you do not submit an approvable state plan the EPA will develop a Federal plan for your state according to § 60.27 to implement the emission guidelines contained in this subpart. Owners and operators of affected entities not covered by an approved state plan must comply with a Federal plan implemented by the EPA for the state. The Federal plan is an interim action and will be automatically withdrawn when your state plan is approved.
A state may meet its CAA section 111(d) obligations only by submitting a complete state plan or a negative declaration letter (if applicable).
No. The EPA has no formal review process for negative declaration letters. Once your negative declaration letter has been received, the EPA will place a copy in the public docket and publish a notice in the
The authorities that will not be delegated to State, local, or tribal agencies are specified in paragraph (a) of this section.
(a) Approval of alternatives, not already approved by this subpart, to the emissions performance goals in Table 1 to this subpart established under § 60.5755.
(b) [Reserved]
(a) You must include the elements described in paragraphs (a)(1) through (11) of this section in your state plan.
(1) Identification of affected entities, including an inventory of CO
(2) A description of plan approach and the geographic scope of a plan (state or multi-state), including, if relevant, identification of multi-state plan participants and geographic boundaries related to plan elements.
(3) Identification of the state emission performance level for affected entities that will be achieved through implementation of the plan.
(i) The plan must specify the average emissions performance that the plan will achieve for the following periods:
(A) The 10 year interim plan performance period of 2020 through 2029.
(B) The single projection year of 2030.
(ii) The identified emission performance level for each plan performance period in paragraph (a)(3)(i) of this section must be equivalent to or better than the levels of the rate-based CO
(A) For a rate-based CO
(B) For a mass-based CO
(iii) For the interim plan performance period you must identify the emission performance levels anticipated under the plan during each year 2020 through 2029.
(4) A demonstration that the plan is projected to achieve each of the state's emission performance levels for affected entities according to paragraph (a)(3) of this section.
(5) Identification of emission standards for each affected entity, compliance periods for each emission standard, and demonstration that the emission standards are, when taken together, sufficiently protective to meet the state emissions performance level.
(6) A demonstration that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable with respect to an affected entity.
(7) If your state plan does not require achievement of the full level of required emission performance, and the identified interim increments of performance in paragraph (a)(3)(iii) of this section, through emission limits on EGUs, the plan must specify the following:
(i) Program implementation milestones (e.g., start of an end-use energy efficiency program, retirement of an affected EGU, or increase in portfolio requirements under a renewable portfolio standard) and milestone dates that are appropriate to the requirements, programs, and measures included in the plan.
(ii) Corrective measures that will be implemented in the event that the comparison required by § 60.5815(b) of projected versus actual emissions performance of affected entities shows that actual emissions performance is greater than 10 percent in excess to projected plan performance for the period described in § 60.5775(c)(1), and a process and schedule for implementing such corrective measures.
(8) Identification of applicable monitoring, reporting, and recordkeeping requirements for each affected entity. If applicable, these requirements must be consistent with the requirements specified in § 60.5810.
(9) Description of the process, contents, and schedule for annual state reporting to the EPA about plan implementation and progress including information required under § 60.5815.
(10) Certification that the hearing on the state plan was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission.
(11) Supporting material including:
(i) Materials demonstrating the state's legal authority to carry out each component of its plan, including emissions standards;
(ii) Materials supporting the projected emissions performance level that will be achieved by affected entities under the plan, according to paragraph (a)(4) of this section;
(iii) Materials supporting the projected mass-based emission performance goal, calculated pursuant to § 60.5770, if applicable; and
(iv) Materials necessary to support evaluation of the plan by the EPA.
(b) You must follow the requirements of subpart B of this part (Adoption and Submittal of state plans for Designated Facilities) and demonstrate that they were met in your state plan.
A multi-state plan may be submitted, provided it is signed by authorized officials for each of the states participating in the multi-state plan. In this instance, the joint submittal will have the same legal effect as an individual submittal for each participating state. A multi-state plan will include all the required elements for a single-state plan specified in § 60.5740(a). A multi-state plan, if submitted by a state, must:
(a) Demonstrate CO
(1) For states demonstrating performance based on the CO
(2) For states demonstrating performance based on mass CO
(b) Assign among states, according to a formula in the multi-state plan, avoided CO
(a) Yes, you may include existing requirements, programs and measures in your plan according to paragraphs (b) through (d) of this section.
(b) Existing state programs, requirements, and measures, may qualify for use in demonstrating that a state plan achieves the required level of emission performance specified in a plan, according to § 60.5740(a)(3).
(c) Existing state programs, requirements, and measures, may qualify for use in projecting that a state plan will achieve the required level of emission performance specified in a plan, according to § 60.5740(a)(4).
(d) Emission impacts of existing programs, requirements, and measures that occur during a plan performance period may be recognized in meeting or projecting CO
(1) Actions taken pursuant to an existing state program, requirement, or measure, such as compliance with a regulatory obligation or initiation of an action related to a program or measure, must occur after June 18, 2014; and
(2) The existing state program, requirement, or measure, and any related actions taken pursuant to such program, requirement, or measure, meet the applicable requirements pursuant to § 60.5740(a) and § 60.5780.
(a) You must submit your state plan with the information in § 60.5740 by June 30, 2016 unless you are submitting a request for extension according to paragraphs (b) or (c) of this section.
(b) For a state seeking a one year extension for a complete plan submittal you must include the information in § 60.5760(a) in a submittal by June 30, 2016 to receive an extension to submit your complete state plan by June 30, 2017.
(c) For states in a multi-state plan seeking a two year extension for a complete plan submittal you must include the information in § 60.5760(a) in a submittal by June 30, 2016 to receive an extension to submit your complete multi-state plan by June 30, 2018.
(a) You must include the following required elements in an initial submittal in lieu of a complete state plan:
(1) A description of the plan approach and progress made to date in developing each of the plan elements in § 60.5740;
(2) An initial projection of the level of emission performance that will be achieved under the complete plan;
(3) A commitment by the state to maintain existing state programs and
(4) Justification of why additional time is needed to submit a complete plan;
(5) A comprehensive roadmap for completing the plan, including process, analytical methods and schedule (including milestones) specifying when all necessary plan components will be complete (e.g., projection of emission performance; implementing legislation, regulations and agreements; necessary approvals);
(6) Identification of existing and future programs, requirements, and measures the state intends to include in the plan;
(7) If a multi-state plan is being developed, an executed agreement(s) with other states (e.g., MOU) participating in the development of the multistate plan; and
(8) A commitment to submit a complete plan by June 30, 2017, for a single-state plan, or June 30, 2018, for a multi-state plan, and actions the state will take to show progress in addressing incomplete plan components prior to submittal of the complete plan.
(9) A description of all steps the state has already taken in furtherance of actions needed to finalize a complete plan.
(10) Evidence of an opportunity for public comment and a response to any significant comments received on issues relating to the approvability of the initial plan.
(b) You must submit either a complete state plan or an initial submittal by June 30, 2016. Where an initial submittal is submitted in lieu of a complete state plan the due date of a complete state plan will be June 30, 2017, for a single-state plan, or June 30, 2018, for a multi-state plan unless a state is notified within 60 days of the EPA receiving the initial submittal in paragraph (a) of this section that the EPA finds the initial submittal does not meet the requirements listed in paragraph (a) of this section.
(a) The annual average state rate-based CO
(b)[Reserved]
(a) If the plan adopts a mass-based goal according to § 60.5740(a)(3), the plan must identify the mass-based goal, in tons of CO
(1) The process, tools, methods, and assumptions used in the conversion of the rate-based goal must be included in your state plan according to § 60.5740(a)(11).
(2) The material supporting the conversion of the rate-based goal, including results, data, and descriptions, must be include in a state plan according to § 60.5740(a)(11).
(3) The conversion must represent the tons of CO
(b) [Reserved]
(a) Your state plan must include a schedule of compliance for each affected entity regulated under the plan.
(b) Your state plan must include compliance periods, as defined in section § 60.5820, for each affected entity regulated under the plan.
(c) For the interim performance period of 2020-2029 your state must meet the requirements in paragraphs (c)(1) and (2) of this section.
(1) Your state plan must include increments of emissions performance (either rate based or mass based with respect to the interim level of performance set in the state plan) within the interim performance period for every 2-rolling calendar years starting January 1, 2020 and ending in 2028 (i.e. 2020-2021, 2021-2022, 2022-2023, etc.), unless other periods that ensure regular progress in the interim period are approved by the Administrator.
(2) At the end of 2029 your state must meet the interim emissions performance level specified in § 60.5740(a)(3) as averaged over the plan performance period 2020-2029.
(d) During the final performance period, 2030 and thereafter, your state must meet the final emission performance level specified in § 60.5740(a)(3) on a 3-calendar year rolling average starting January 1, 2030 (i.e., 2030-2032, 2031-2033, 2032-2034, etc.).
(e) You must include the provisions of your state plan which demonstrate progress and compliance with the requirements in this § 60.5775 and § 60.5740 in your state's annual report required in § 60.5815.
(a) Your state plan shall include emission standard(s) that are quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected entity. The plan shall include the methods by which each emission standard meets each of the following requirements in paragraphs (b) through (f) of this section.
(b) An emission standard is quantifiable with respect to an affected entity if it can be reliably measured, in a manner that can be replicated.
(c) An emission standard is verifiable with respect to an affected entity if adequate monitoring, recordkeeping and reporting requirements are in place to enable the state and the Administrator to independently evaluate, measure, and verify compliance with the emission standard.
(d) An emission standard is non-duplicative with respect to an affected entity if it is not already incorporated as an emission standard in another state plan unless incorporated in multi-state plan.
(e) An emission standard is permanent with respect to an affected entity if the emission standard must be met for each compliance period, or unless it is replaced by another emission standard in an approved plan revision, or the state demonstrates in an approved plan revision that the emission reductions from the emission standard are no longer necessary for the state to meet its state level of performance.
(f) An emission standard is enforceable against an affected entity if:
(1) A technically accurate limitation or requirement and the time period for
(2) Compliance requirements are clearly defined;
(3) The affected entities responsible for compliance and liable for violations can be identified;
(4) Each compliance activity or measure is enforceable as a practical matter; and
(5) The Administrator and the state maintain the ability to enforce violations and secure appropriate corrective actions pursuant to sections 113(a) through (h) of the Act.
State plans can only be revised with approval by the Administrator. If one (or more) of the elements of the state plan set in § 60.5740 require revision with respect to reaching the emission performance goal set in § 60.5765 a request may be submitted to the Administrator indicating the proposed corrections to the state plan to ensure the emission performance goal is met.
(a) This subpart does not directly affect EGU owners and operators in your state. However, EGU owners and operators must comply with the state plan that a state develops to implement the emission guidelines contained in this subpart.
(b) If a state does not submit an approvable plan or initial submittal to implement and enforce the emission guidelines contained in this subpart by June 30, 2016, the EPA will implement and enforce a Federal plan, as provided in § 60.5740, to ensure that each affected EGU within the state that commenced construction on or before January 8, 2014 reaches compliance with all the provisions of this subpart.
(a) The EGUs that must be addressed by your state plan are any affected steam generating unit, IGCC, or stationary combustion turbine that commences construction on or before January 8, 2014.
(b) An affected EGU is a steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine that meets the relevant applicability conditions specified in paragraph (b)(1) or (2) of this section.
(1) A steam generating unit or IGCC that has a base load rating greater than 73 MW (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel) and was constructed for the purpose of supplying one-third or more of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution system on an annual basis.
(2) A stationary combustion turbine that has a base load rating greater than 73 MW (250 MMBtu/h), was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3-year rolling average basis, combusts fossil fuel for more than 10.0 percent of the heat input during a 3-year rolling average basis and combusts over 90% natural gas on a heat input basis on a 3-year rolling average basis.
Affected EGUs that are exempt from your state plan include: those that are subject to subpart TTTT as a result of commencing construction or reconstruction after the subpart TTTT applicability date; and those subject to subpart TTTT as a result of commencing modification or reconstruction prior becoming subject to an applicable state plan.
(a) A state plan must include monitoring that is no less stringent that what is described in (a)(1) through (6) of this section.
(1) If an affected EGU is required to meet a rate based emission standard they must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.
(2) An affected EGU must measure the hourly CO
(i) An affected EGU must install, certify, operate, maintain, and calibrate a CO
(ii) For each monitoring system an affected EGU uses to determine the CO
(iii) An affected EGU must use a laser device to measure the dimensions of each exhaust gas stack or duct at the flow monitor and the reference method sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, an affected EGU must measure the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, an affected EGU must measure each dimension (i.e., depth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, an affected EGU must repeat these measurements at the new location.
(iv) An affected EGU must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO
(v) If an affected EGU chooses to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, they must use a calibrated Type-S pitot tube or pitot tube assembly. An affected EGU must not use the default Type-S pitot tube coefficient.
(3) If an affected EGU exclusively combusts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, they may determine the hourly CO
(i) An affected EGU must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(ii) An affected EGU may determine site-specific carbon-based F-factors (F
(4) An affected EGU must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis net electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Further, an affected EGU that is a combined heat and power facility must install, calibrate, maintain and operate equipment to continuously measure and record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with net electric output to determine net energy output.
(5) In accordance with § 60.13(g), if two or more affected EGUs that implement the continuous emissions monitoring provisions in paragraph (a)(2) of this section share a common exhaust gas stack and are subject to the same emissions standard, they may monitor the hourly CO
(6) In accordance with § 60.13(g), if the exhaust gases from an affected EGU that implements the continuous emissions monitoring provisions in paragraph (a)(2) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), they must monitor the hourly CO
(b) An affected EGU must maintain records for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.
(1) An affected EGU must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. An affected EGU may maintain the records off site and electronically for the remaining year(s).
(c) An affected EGU must include in a report required by the state plan covering each compliance period all hourly CO
(a) States must keep records of all plan components, plan requirements, supporting documentation, and the status of meeting the plan requirements defined in the state plan on an annual basis during the interim plan performance period from 2020-2029. After 2029 states must keep records of all information that is used to support any continued effort to meet the final emissions performance goal.
(b) States must keep records of all data submitted by each affected entity that is used to determine compliance with each affected entity's emissions standard.
(c) If a state has a requirement for hourly CO
(d) A state must keep records at minimum for 20 years.
(a) You must submit an annual report covering each calendar year no later than July 1 of the following year, starting July 1 2021. The annual report must include the following:
(1) The level of emissions performance achieved by all affected entities and identification of whether affected entities are on schedule to meet the applicable level of emissions performance for affected entities during the plan performance period and compliance periods, as specified in the plan.
(2) The level of emissions performance achieved by all affected EGUs during the reporting period, and prior reporting periods, expressed as average CO
(3) A list of affected entities and their compliance status with the applicable emissions standards specified in the state plan.
(4) A list of all affected EGUs and their reported CO
(5) All other required information, as specified in your state plan according to § 60.5740(a)(9).
(6) All information required by § 60.5775(e).
(b) For each two-year period in § 60.5775(c)(1), you must compare the average CO
(c) You must include in your 2029 annual report (which is subsequently due by July 1, 2030) the calculation of average emissions over the 2020-2029 interim performance period used to determine compliance with your interim emission performance level. The calculated value must be in units consistent with your interim emission performance level.
(d) You must include in each report, starting with the 2032 annual report (which is subsequently due by July 1, 2033), a 3-calendar year rolling average used to determine compliance with the final emission performance level. The calculated value must be in units consistent with your final emission performance level.
As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subparts A (General Provisions) and B of this part.
(1) The net electric or mechanical output from the affected facility, plus 75 percent of the useful thermal output measured relative to SATP conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).
(2) For combined heat and power facilities where at least 20.0 percent of
Environmental Protection Agency.
Proposed rule.
The Environmental Protection Agency (EPA) is proposing standards of performance for emissions of greenhouse gases from affected modified and reconstructed fossil fuel-fired electric utility generating units. Specifically, the EPA is proposing standards to limit emissions of carbon dioxide from affected modified and reconstructed electric utility steam generating units and from natural gas-fired stationary combustion turbines. This rule, as proposed, would continue progress already underway to reduce carbon dioxide emissions from the electric power sector in the United States.
The EPA requests that you also submit a separate copy of your comments to the contact person identified below (see
The
In addition to being available in the docket, an electronic copy of this proposed rule will be available on the World Wide Web (WWW). Following signature, a copy of this proposed rule will be posted at the following address:
Mr. Christian Fellner, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711; telephone number (919)541-4003, facsimile number (919)541-5450; email address:
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan (CAP), President Obama issued a Presidential Memorandum directing the EPA to issue a new proposal to address carbon pollution from new power plants by September 30, 2013, and to issue “standards, regulations, or guidelines, as appropriate, which address carbon pollution from modified, reconstructed, and existing power plants.” Consistent with the Presidential Memorandum, on September 20, 2013, the Administrator signed proposed carbon pollution standards for newly constructed fossil fuel-fired power plants. The proposal was published on January 8, 2014 (79 FR 1430; January 2014 proposal). Specifically, under the authority of CAA section 111(b), the EPA proposed new source performance standards (NSPS) to limit emissions of carbon dioxide (CO
In this action, under the authority of CAA section 111(b), the EPA is proposing standards of performance to limit emissions of CO
In a separate action, under CAA section 111(d), the EPA is proposing emission guidelines for states to use in developing plans to limit CO
The proposed standards for the affected modified and reconstructed sources are summarized below in Table 1.
For the reasons discussed in the “Legal Memorandum”
It should be noted that the EPA intends each standard of performance proposed in this rulemaking to be severable from each other standard of performance, such that if one or more of the standards of performance were to be remanded or vacated in a court challenge, the EPA intends for the other standards to remain in effect. The EPA also intends each BSER determination or alternative determination, as applicable, for modified utility boilers and IGCC units, and for modified natural gas-fired stationary combustion turbines, to be severable from each other BSER determination. In all of these cases, the EPA believes that the standards of performance and associated best systems of emission reduction operate independently of each other.
The EPA is proposing that the form of the standards for modified and reconstructed natural gas-fired stationary combustion turbines be consistent with the standards for newly constructed natural gas-fired stationary combustion turbines proposed on January 8, 2014 (79 FR 1430). In that proposal, the EPA proposed standards for turbines on a gross output basis, but also took comment on standards on a net output basis. The EPA is similarly proposing standards on a gross output basis, while soliciting comment on net output based standards, in today's proposal for modified and reconstructed natural gas-fired stationary combustion turbines. To the extent that the EPA finalizes modified and reconstructed standards for stationary combustion turbines that are consistent with the standards for newly constructed stationary combustion turbines, the EPA intends to take the same approach with regards to the use of net or gross output in both final actions.
As explained in the regulatory impact analysis (RIA)
The U.S. Supreme Court ruled, in
Congress established requirements under section 111 of the 1970 CAA to control air pollution from new stationary sources through NSPS. Specifically, as explained in greater detail in section II below, CAA section 111(b) authorizes the EPA to set “standards of performance” for new (including modified) stationary sources from listed source categories to limit emissions of air pollutants to the environment, and the EPA's implementing regulations provide that new sources include reconstructed sources.
For more than four decades, the EPA has used its authority under CAA section 111 to set cost-effective emission standards that ensure newly constructed, reconstructed and modified stationary sources use the best performing technologies to limit emissions of harmful air pollutants. In this proposal, the EPA is following the same well-established interpretation and application of the law under CAA section 111 to address GHG emissions from modified and reconstructed fossil fuel-fired electric steam generating units and natural gas-fired stationary combustion turbines.
The proposed standards of performance would regulate GHG emissions from modified and reconstructed (1) fossil fuel-fired electric steam generating units—utility boilers and IGCC units—whose non-
The CAA and the EPA's implementing regulations define a “modification,” for purposes of NSPS applicability, as a physical or operational change that increases the source's maximum achievable hourly rate of emissions, with certain exceptions.
Under the EPA's 1975 framework regulations covering CAA section 111 standards of performance, “reconstruction” means the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards.
GHG pollution threatens the American public's health and welfare by contributing to long-lasting changes in our climate system that can have a range of negative effects on human health and the environment. The impacts could include: Longer, more intense and more frequent heat waves; more intense precipitation events and storm surges; less precipitation and more prolonged droughts in the West and Southwest; increased frequency and severity of short-term droughts in some other U.S. regions; more fires and insect pest outbreaks in American forests, especially in the West; and increased ground level ozone pollution, otherwise known as smog, which has been linked to asthma and premature death. Health risks from climate change are especially serious for children, the elderly and those with heart and respiratory problems.
Unlike most other air pollutants, GHGs may persist in the atmosphere from decades to millennia, depending on the specific GHG. This special characteristic makes it crucial to act now to limit GHG emissions from fossil fuel-fired power plants, specifically emissions of CO
As previously noted, on June 25, 2013, President Obama issued a Presidential Memorandum directing the EPA to address carbon pollution from the power sector. As an initial step to limit carbon pollution from power plants, on January 8, 2014, the EPA published a proposed rule to limit GHG emissions from newly constructed fossil fuel-fired electric steam generating units (utility boilers and IGCC units) and newly constructed natural gas-fired stationary combustion turbines. The EPA is now taking another step to limit carbon pollution in this country by issuing a proposed rule to limit GHG emissions from modified and reconstructed fossil fuel-fired electric steam generating units and modified and reconstructed natural gas-fired stationary combustion turbines.
Although we expect that the modification and reconstruction standards of performance in this rulemaking will apply to few sources—since there have been a limited number in the past—these standards serve another important purpose that may affect a larger number of sources: Providing an incentive, and the information needed, for existing sources to structure their actions to achieve their operating and business goals without triggering the modification or reconstruction standards. For example, the modification standard encourages existing sources that undertake physical or operational changes to do so in a manner that does not increase their emission rate.
CAA section 111(b) requires the EPA to establish standards of performance that reflect the degree of emission limitation that is achievable through the application of the “best system of emission reduction” which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the EPA determines has been adequately demonstrated. The text and legislative history of CAA section 111, as well as relevant court decisions identify the factors for the EPA to consider in making a BSER determination. They include, among others, whether the system of emission reduction is technically feasible, whether the costs of the system are reasonable, the amount of emissions reductions that the system would generate, and whether the standard would effectively promote further deployment or development of advanced technologies. The case law addressing section 111 makes it clear that the EPA has discretion in weighing these factors, and that as a result, the EPA may weigh them differently for different types of sources or air pollutants. See further discussion of this case law in section VI below.
For each of the standards being proposed in today's action, the EPA considered a number of alternatives and evaluated them against the factors.
The BSER we are proposing for each category of affected sources and the proposed standards of performance based on these BSER—as described immediately below—are based on that evaluation, as discussed in sections VI-IX below.
The EPA proposes that the BSER for modified fossil fuel-fired boilers and IGCC units is each unit's own best potential performance based on a combination of best operating practices and equipment upgrades. Specifically, the EPA is proposing unit-specific emission standards consistent with this BSER determination and is co-proposing two alternative standards for modified utility steam generating units. In the first co-proposed alternative, modified utility boilers and IGCC units would be subject to a single emission standard. Specifically, under the first co-proposed alternative, a modified source would be required to meet a unit-specific emission limit determined by the affected source's best demonstrated historical performance (in the years from 2002 to the time of the modification) with an additional 2 percent emission reduction. The EPA has determined that this standard can be met through a combination of best operating practices and equipment upgrades. To account for facilities that have already implemented best practices and equipment upgrades, the proposal also specifies that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed EGUs. The EPA also solicits comment on whether, for units that have become subject to a CAA section 111(d) plan, the period of best historical performance should be the years from 2002 to the time when the unit becomes subject to the CAA section 111(d) plan, rather than to the time of the modification. This could address the concern that sources that make improvements to their CO
It is our interpretation that, as we discuss in detail in the Legal Memorandum,
For modified natural gas-fired stationary combustion turbines, the EPA is proposing standards of performance based on efficient Natural Gas Combined Cycle (NGCC) technology as the BSER. The emission limits proposed for these sources are 1,000 lb CO
For reconstructed utility boilers and IGCC units, the EPA is proposing a standard of performance with BSER based on the most efficient generating technology for these types of units (i.e., reconstructing the boiler to use higher steam, temperature and pressure, even if the boiler was not originally designed to do so
As discussed in the Legal Memorandum,
The EPA is proposing to find efficient NGCC technology to be the BSER for reconstructed stationary combustion turbines. Therefore, the EPA is proposing that larger units be required to meet a standard of 1,000 lb CO
A reconstruction would have no effect on the applicability of an approved CAA section 111(d) plan on the existing source; thus, a source that is subject to requirements in a CAA section 111(d) plan would remain subject to those requirements, even after reconstruction.
In the January 2014 proposal of carbon pollution standards for newly constructed power plants (79 FR 1430), the EPA co-proposed two options for codifying applicable requirements for covered sources. Under the first option the EPA proposed to codify the standards of performance for the respective sources within existing 40 CFR part 60 subparts so that applicable GHG standards for electric utility steam generating units would be included in subpart Da and applicable GHG standards for stationary combustion turbines would be included in subpart KKKK. Under the second option, the EPA co-proposed to create a new subpart TTTT and to include all GHG standards of performance for covered sources in that newly created subpart.
In this action for modified and reconstructed sources, the EPA co-proposes the same two options for codifying the applicable standards. For consistency, the EPA intends—when it takes final action on this proposal and on the January 2014 proposal for newly constructed sources, respectively—to codify the standards in the same way for the sources addressed under the two proposals.
Section II of this preamble provides a brief summary of background information on climate change impacts of GHG emissions, GHG emissions from fossil-fuel fired EGUs, the utility power sector, the statutory and regulatory background relevant to this rulemaking, and the EPA's stakeholder outreach activities. Section II also contains additional information on the regulatory and litigation history of CAA section 111.
The specific proposed requirements for modified and reconstructed sources are described in detail in section III of this preamble. The rationale for reliance on a rational basis to regulate GHG emissions from fossil fuel-fired EGUs and the rationale for the applicability requirements in today's proposal are presented in sections IV and V of this preamble, respectively. Sections VI through IX of this preamble describe the rationale for each of the proposed emission standards, including an explanation of the determination of the BSER for reconstructed fossil fuel-fired utility boilers and IGCC units and modified fossil fuel-fired utility boilers and IGCC units, as well as for
It should be noted that this rulemaking overlaps in certain respects with two other related rulemakings: The January 2014 proposed rulemaking for CO
The entities potentially affected by the proposed standards are shown in Table 2 below.
This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by this proposed action. To determine whether your facility, company, business, or organization, would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 (General Provisions).
In this section,
In 2009, the EPA Administrator issued the document known as the Endangerment Finding under CAA section 202(a)(1).
Climate change caused by human emissions of GHGs threatens public health in multiple ways. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the United States. Compared to a future without climate change, climate change is expected to increase ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst ozone problems, and thereby increase the risk of morbidity and mortality. Other public health threats also stem from projected increases in intensity or frequency of extreme weather associated with climate change, such as increased hurricane intensity, increased frequency of intense storms, and heavy precipitation. Increased coastal storms and storm surges due to rising sea levels are expected to cause increased drownings and other health impacts. Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects.
Climate change caused by human emissions of GHGs also threatens public welfare in multiple ways. Climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to
As outlined in Section VIII.A. of the 2009 Endangerment Finding, the EPA's approach to providing the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare was to rely primarily upon the recent, major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. Since the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, a number of such assessments have been released. These assessments include the IPCC's 2012 “Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation” (SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP's 2014 “Climate Change Impacts in the United States” (Climate Change Impacts), and the NRC's 2010 “Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean” (Ocean Acidification), 2011 “Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia” (Climate Stabilization Targets), 2011 “National Security Implications for U.S. Naval Forces” (National Security Implications), 2011 “Understanding Earth's Deep Past: Lessons for Our Climate Future” (Understanding Earth's Deep Past), 2012 “Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future”, 2012 “Climate and Social Stress: Implications for Security Analysis” (Climate and Social Stress), and 2013 “Abrupt Impacts of Climate Change” (Abrupt Impacts) assessments.
The EPA has reviewed these new assessments and finds that the improved understanding of the climate system they present strengthens the case that GHGs endanger public health and welfare.
In addition, these assessments highlight the urgency of the situation as the concentration of CO
What this means, as stated in another NRC assessment, is that:
Emissions of carbon dioxide from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the evolution of Earth's climate. Because carbon dioxide in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe. Therefore, emission reductions choices made today matter in determining impacts experienced not just over the next few decades, but in the coming centuries and millennia.
Moreover, due to the time-lags inherent in the Earth's climate, the Climate Stabilization Targets assessment notes that the full warming from any given concentration of CO
The recently released USGCRP “National Climate Assessment”
These assessments underscore the urgency of reducing emissions now: Today's emissions will otherwise lead to raised atmospheric concentrations for thousands of years, and raised Earth system temperatures for even longer. Emission reductions today will benefit the public health and public welfare of current and future generations.
Finally, it should be noted that the concentration of CO
Fossil fuel-fired EGUs are by far the largest emitters of GHGs, primarily in the form of CO
The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks
Total
Electricity in the United States is generated by a range of sources—from power plants that use fossil fuels like coal, oil, and natural gas, to non-fossil sources, such as nuclear, solar, wind and hydroelectric power. In 2013, over 67 percent of power in the U.S. was generated from the combustion of coal, natural gas, and other fossil fuels, over 40 percent from coal and over 26 percent from natural gas.
Natural gas-fired EGUs typically use one of two technologies: NGCC or simple cycle combustion turbines. NGCC units first generate power from a combustion turbine (the combustion cycle). The unused heat from the combustion turbine is then routed to a heat recovery steam generator (HRSG) that generates steam which is used to produce power using a steam turbine (the steam cycle). Combining these generation cycles increases the overall efficiency of the system. Simple cycle combustion turbines use a single combustion turbine to produce electricity (i.e., there is no heat recovery). The power output from these simple cycle combustion turbines can be easily ramped up and down making them ideal for “peaking” operations.
Coal-fired utility boilers are primarily either pulverized coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is crushed (pulverized) into a powder in order to increase its surface area. The coal powder is then blown into a boiler and burned. In a coal-fired boiler using FB combustion, the coal is burned in a layer of heated particles suspended in flowing air.
Power can also be generated using gasification technology. An IGCC unit gasifies coal or petroleum coke to form a syngas composed of carbon monoxide and hydrogen, which can be combusted in a combined cycle system to generate power.
CAA section 111 authorizes the EPA to prescribe new source performance standards (NSPS) applicable to certain new stationary sources (including
Once the EPA has listed a source category, the EPA proposes and then promulgates “standards of performance” for “new sources” in the category.
The EPA's 1975 framework regulations also provide that an existing source is considered a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards.
CAA section 111(a)(1) defines a “standard of performance” as a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. This definition makes clear that the standard of performance must be based on “the best system of emission reduction . . . adequately demonstrated” (BSER). The standard that the EPA develops, based on the BSER, is commonly a numeric emission limit, expressed as a performance level (e.g., a rate-based standard). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard of performance. Rather, sources generally may select any measure or combination of measures that will achieve the emissions level of the standard.
When the EPA establishes NSPS for new sources in a particular source category, the EPA is also required, under CAA section 111(d)(1), to establish requirements for existing sources in that source category for any air pollutant that, in general, is not regulated under the CAA section 109 requirements for the National Ambient Air Quality Standards or regulated under the CAA section 112 requirements for hazardous air pollutants. Unlike CAA section 111(b), which gives EPA direct authority to set national standards, CAA section 111(d) requires the EPA to promulgate emission guidelines directing states to develop and submit, for EPA approval, state plans that include standards of performance for the existing sources.
In 1971, the EPA initially included fossil fuel-fired (which includes natural gas, petroleum and coal) EGUs that use steam-generating boilers in a category that it listed under CAA section 111(b)(1)(A),
The EPA has revised those regulations, and in some instances, has revised the codifications (that is, the 40 CFR part 60 subparts), several times over the ensuing decades. In 1979, the EPA divided subpart D into 3 subparts—Da (“Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978”), Db (“Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units”) and Dc (“Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units”)—in order to codify separate requirements that it established for these subcategories.
The EPA promulgated amendments to subpart Da in 2006, which included new standards of performance for criteria pollutants for EGUs, but no standards of performance for GHG emissions.
The EPA has engaged extensively with a broad range of stakeholders and the general public regarding climate change, carbon pollution from power plants, and carbon pollution reduction opportunities. These stakeholders included industry and electric utility representatives, state and local officials, tribal officials, labor unions and non-governmental organizations.
In February and March 2011, early in the process of developing carbon pollution standards for new power plants, the EPA held five listening sessions to obtain information and input from key stakeholders and the public.
The EPA has conducted subsequent outreach sessions: The vast majority of which occurred between September 2013 and November 2013. The agency held 11 public listening sessions; one national listening session in Washington, DC and 10 listening sessions in locations across the country. In addition to the 11 public listening sessions, the EPA has held hundreds of meetings with individual stakeholder groups, and meetings that brought together a variety of stakeholders to discuss a wide range of issues related to the electricity sector and regulation of GHGs under the CAA. The agency provided and encouraged multiple opportunities to engage with each one of the 50 states. The agency met with electric utility associations and electricity grid operators. Agency officials have engaged with labor unions and with leaders representing large and small industries. Because of the focus of the standard on the electricity sector, many of the EPA's meetings with industry have been with utilities and industry representatives directly related to the electricity sector. The agency has also met with energy industries such as coal and natural gas interests. In addition, the agency has met with companies that offer new technology to prevent or reduce carbon pollution, including companies that represent renewable energy and energy efficiency interests. The EPA has also met with representatives of energy intensive industries, such as the iron and steel and aluminum industries, to help understand the issues related to large industrial purchasers of electricity. Agency officials engaged with representatives of environmental justice organizations, environmental groups, and religious organizations.
Although this stakeholder outreach was primarily framed around the GHG emission guidelines for existing EGUs, the outreach encompassed issues relevant to this proposed rulemaking for modified and reconstructed EGUs. For example, existing EGUs would be subject to standards for modified and reconstructed EGUs should they undertake modification or reconstruction actions, and, thus it is important that we understand previous state and stakeholder experience with reducing CO
A detailed discussion of this stakeholder outreach is included in the preamble to the GHG emission guidelines for existing affected EGUs being proposed in a separate action today.
The EPA's current regulations
Based on current information, the EPA believes that projects may involve equipment changes to improve efficiency that could have the effect of increasing a source's maximum achievable hourly emission rate (lb CO
There are, however, some actions that could potentially trigger the modification provisions of CAA section 111(b). For example, in some cases, generation from a fossil fuel-fired electric utility steam generating unit is limited not by the size of the boiler, but by other factors, such as the size of the steam turbine or limitations in the particulate control equipment that, in turn, limit the amount of coal that can be combusted. If the steam turbine or particulate control device is upgraded, more coal can be combusted in the boiler, increasing hourly emissions.
Our base of knowledge concerning the types of NSPS modifications has depended largely on self-reporting by power plants and on the enforcement actions brought against power plants. Over the lengthy history of the NSPS program, the number of modifications that we are aware of is limited.
In the April 13, 2012 proposed Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units (77 FR 22392),
Many of those comments emphasized that a standard of performance that is based on carbon capture and storage (CCS) (or partial CCS) is not appropriate for modified EGUs. Some commenters suggested that a well-designed CAA section 111(d) program could obviate the need to set separate standards of performance for modified sources. Several commenters disagreed with EPA's assertion that it lacked adequate information to propose standards for modified sources (at that time), stating that proposed standards should be based on energy efficiency measures.
The EPA's framework regulations, interpreting the definition of “new source” in CAA section 111(a)(2), provide that an existing source, “upon reconstruction,” becomes subject to the standard of performance for new sources.
Thus, a reconstruction occurs if the existing source replaces components to such an extent that the capital costs of the new components exceed 50 percent of the capital costs of an entirely new facility, even if the existing source does not increase its emissions. In addition, the component replacement constitutes a reconstruction only if it is technologically and economically feasible for the source to meet the applicable standards. The purpose of the reconstruction provision is to avoid creating any regulatory incentive to perpetuate the operation of a facility, instead of replacing it at the end of its useful life with a newly constructed affected facility.
The regulations require the owner or operator of an existing source that proposes to replace components to an extent that exceeds the 50 percent level to notify the EPA and provide specified information. This information must include: The name and address of the owner or operator; the location of the existing facility; a brief description of the existing facility and the components which are to be replaced; a description of existing and proposed air pollution control equipment; an estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facility; the estimated life of the existing facility after the replacements; and, a discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements. The regulations require the EPA to determine, within a specified time period, whether the proposed replacement constitutes a reconstruction.
Historically, few EGUs have undertaken reconstructions. Because of the relative prices of coal and natural gas, and the relative costs of reconstructing an existing coal-fired EGU and constructing an entirely new NGCC unit, the EPA expects that few existing coal-fired EGUs will undertake projects that will qualify the unit to be a reconstructed source during the analysis period of this rulemaking (i.e., through 2025). The EPA also does not expect existing NGCC units to undertake reconstructions during the analysis period (i.e., through 2025) because most of them are relatively young (over 80 percent of the NGCC fleet came on-line after 2000).
While there are specific provisions in the EPA's implementing regulations at 40 CFR 60.15 on what constitutes a reconstructed source (as just described), there is not such guidance on when an existing source replaces components to such a degree that it goes beyond a reconstruction and becomes essentially a newly constructed source. Historically there has been little need to distinguish between reconstructed sources and newly constructed sources as the standards of performance are typically the same for either. However, the standards proposed in today's action are different—for reasons we explain later—and, therefore, there is a need to clearly delineate between a reconstructed source and a newly constructed source. For example, it is clear that an entirely new greenfield facility would constitute a newly constructed source. It is EPA's view that, a new unit that is built on property contiguous with an existing source—but not in the same footprint as the existing source—would also constitute a newly constructed source. And, it is EPA's view that a unit that entirely, or for all practical purposes, completely replaces an existing sources by being constructed on the replaced source's existing footprint would also constitute a newly constructed source. The EPA solicits comment on the delineation between a reconstructed source, which would be subject to standards proposed in today's action, and a newly constructed source, which would be subject to standards proposed in the January 2014 proposal (79 FR 1430), for those situations where significant equipment is being replaced (enough to exceed the reconstruction threshold) but the entire unit is not being rebuilt.
In addition, the EPA requests comment on having an upper capital cost threshold for reconstruction, such that facilities that exceed that threshold would be subject to the standard of performance for newly constructed sources. With respect to this concept, the EPA requests comment on both: (1) The idea of having an upper threshold and (2) the appropriate upper threshold. With respect to the appropriate upper threshold, EPA specifically requests comment on an upper threshold within the range of 75 to 100 percent of the cost of an entirely new and comparable facility. Finally, the EPA requests comment on whether this upper threshold should be coupled with a provision comparable to 40 CFR 60.15(b)(2) and 60.15(f)(4), such that a facility that exceeded the upper threshold would not be subject to the new construction standard if it was technologically and economically infeasible for that facility to meet the new construction standard.
In the April 13, 2012 proposed Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units (77 FR 22392), the EPA did not propose standards of performance for reconstructed sources; however, it did specifically request comment on the types of reconstructions that may be expected and on the appropriate control measures that may be applied. The agency received a number of comments addressing standards for reconstructed EGUs.
Many of the comments on the April 13, 2012 proposal supported a delay in proposing standards for reconstructed sources. Others did not favor the delay and suggested, instead, that reconstructed sources be subject to the same standard as newly constructed sources. One commenter expressed concern that an existing source that elected to retrofit with CCS technology (perhaps in reliance on enhanced oil recovery (EOR) markets) might trigger the requirements for a reconstruction due to the high cost of CCS technology. The commenter suggested that the EPA exclude the cost of retrofitting CCS technology in order to eliminate barriers to voluntary use of that technology. Several commenters expressed concern that a reconstruction could be essentially a new plant built on a few remaining parts of an old plant. The commenters expressed concern that such reconstructed sources would face a standard that is much less stringent than a newly constructed greenfield source.
We generally refer to fossil fuel-fired electric generating units that would be subject to an emission standard in this rulemaking as “affected” or “covered” sources, units, facilities or simply as EGUs. These sources meet both the definition of “affected” and “covered” EGUs subject to an emission standard as provided by this proposed rule, and the criteria for being considered “modified” and “reconstructed” sources as defined under the provisions of CAA section 111 and the EPA's regulations.
The EPA is proposing generally similar applicability requirements, for purposes of this rule, that the EPA proposed in the January 2014 proposal.
To be considered an EGU under subpart Da, the boiler or IGCC must be: (1) Capable of combusting more than 250 MMBtu/h heat input of fossil fuel,
We are proposing and soliciting comment on an additional amendment, not included in the January 2014 proposal, to clarify that net-electric sales, for applicability purposes, includes electricity supplied to other facilities that produce electricity to offset auxiliary loads. Without this amendment, smaller EGUs that are co-located with larger EGUs could claim that they do not meet the rule applicability criteria because their generated power is used to offset the parasitic loads of the larger facility. We are also soliciting comment if the 10 percent fossil fuel use criteria should be based on 3 consecutive calendar years or on a 3 year rolling average basis.
Consistent with the January 2014 proposal, we are proposing several additional adjustments to the way applicability is currently determined under subpart Da for purposes of modifications and reconstructions. First, we are proposing that the definition of “potential electric output” be revised to include “or the design net electric output efficiency” as an alternative to the default one-third efficiency value (i.e., the proposed definition is “33 percent
Finally, consistent with the January 2014 proposal, to avoid circumvention of the intent of the emission standards (e.g., by having auxiliary equipment provide steam to the EGU to increase the output of the EGU and not including the CO
This action proposes to set standards only for emissions of CO
We are also not proposing standards for certain types of sources. These include modified and reconstructed boilers and IGCC units that were constructed for the purpose of selling one-third or less of their potential output and 219,000 MWh or less to the grid. These units are not covered under
In this rulemaking, the EPA is proposing standards of performance for CO
The proposed standards of performance for the utility boiler and IGCC category are in the form of net energy output-based CO
As explained earlier, the proposed standards of performance for natural gas-fired stationary combustion turbines are in the form of a gross output-based emission limit expressed in units of mass of CO
The proposed method to calculate compliance is the same as was proposed in the January 2014 proposal. Compliance would be calculated as the sum of the emissions for all operating hours divided by the sum of the useful energy output over a rolling 12-operating-month period. In the alternative, as in the January 2014 proposal, we solicit comment on requiring calculation of compliance on an annual (calendar year) period.
We are proposing additional amendments to the definition of useful thermal output. The current definition excludes energy used to enhance the performance of the affected facility from being considered as useful thermal output. The intent of this restriction is to clarify that thermal energy that is directly used by the affected facility to create additional output (e.g., the economizer) is not counted as useful thermal output. Without this restriction, the energy could be doubled counted—once as useful thermal output and again as electric output. This could also be interpreted to exclude thermal energy used to reduce fuel moisture (e.g., coal drying) as being useful thermal output because it enhances the performance of the affected facility. However, coal-drying could be done at a separate offsite facility by an industrial boiler prior to delivery at the power plant. In that scenario, the CO
The EPA is proposing that affected modified utility boilers and IGCC units must meet a standard of performance based on the source's best potential performance, achieved through a combination of best operating practices and equipment upgrades, as the BSER. The EPA is co-proposing two alternative standards of performance. In the first alternative, modified sources would be required to meet a unit-specific numeric emission standard that is 2 percent lower than the unit's best demonstrated annual performance during the years from 2002 to the year the modification occurs.
Based on analysis of existing data, the EPA has determined that this standard can be met through a combination of best operating practices and equipment upgrades. In an analysis to determine opportunities for heat rate improvement in the U.S. coal-fired utility power fleet, the EPA found that a total of 6 percent improvement, on average, can be achieved through two types of measures: Best operating practices that have the potential to improve heat rate, on average, by 4 percent, and equipment upgrades that have the potential to improve heat rate, on average, by an additional 2 percent.
As we discuss in the Legal Memorandum
In addition, we solicit comment on alternative ways to determine the best potential performance at affected modified utility boilers and IGCC units. Specifically, we are requesting comment on whether the unit-specific numerical emission standard should be based on the single best annual emission rate (for the years 2002 to the year when the modification occurs) or the best three consecutive year average emission rate. We also solicit comment on whether there are circumstances where it would not be appropriate to require that the best historical emission rate be made 2 percent more stringent, or where some other increment of additional stringency should be required.
The EPA also seeks comment on including an additional compliance option for modified utility boilers and IGCC units. Specifically, we seek comment on including uniform emission standards that are similar to the standards proposed for reconstructed utility boilers and IGCC units. Specifically, we seek comment on a standard of 1,900 lb CO
The EPA further solicits comment on whether, in the case of modified utility boilers and IGCC units subject to a CAA section 111(d) plan, there are any circumstances in which the emission limit should be calculated by not including the 2 percent additional emission reduction based on equipment upgrades. This may, for example, be appropriate in cases where the state plan requires heat rate improvements which improve on the source's historical performance, or where the source has recently implemented aggressive measures to improve its operating efficiency, and as a result, the additional 2 percent improvement may be unnecessary or not reasonable.
The EPA also solicits comment on requiring modified utility boilers and IGCC units subject to a CAA section 111(d) plan to take, as their unit-specific emission rate, the lower of (1) the emission rate they are subject to under the CAA section 111(d) plan, or (2) the emission rate that is 2 percent less than the unit's best demonstrated annual performance during the years from 2002 to the year the modification occurs. Similarly, the EPA solicits comment on whether modified utility boilers and IGCC units subject to a CAA section 111(d) plan could be evaluated on a case-by-case basis to determine whether, as their CAA section 111(b) standard, they should continue to be subject to the CAA section 111(d) requirements to which they are subject. One method of doing this might be through a delegation of the EPA's CAA section 111(b) authority over that source to the state administering the applicable CAA section 111(d) plan. Under this option the modified utility boilers and IGCC units would be considered to be only “new sources” under 111(a)(2).
The EPA further seeks comment on whether the time period of the unit's best demonstrated performance should be limited to the years from 2002 to the time that the unit becomes subject to a CAA section 111(d) plan—rather than to the date that the modification occurs. The EPA also seeks comment on whether the time period for best historic performance should be from 2002 to the date of modification—unless the source can provide evidence of significant heat rate improvements that have already been implemented, in which case the time period would be from the year of the first heat rate improvement to the modification.
The EPA also seeks comment on whether, and under what circumstances, a modified utility boiler or IGCC unit that modifies prior to becoming subject to a CAA section 111(d) plan should also be allowed to meet a emission limit that is determined from the results of an energy assessment or audit. The EPA also requests comment on whether this approach should be limited to sources that may have voluntarily, or for any other reason, implemented energy efficiency measures in the time period between 2002 and the date of the modification and whether those sources should be required to provide evidence of those energy efficiency improvements.
The EPA also solicits comment on whether we should—as we have proposed in this action—have different standards of performance for modified utility boilers and IGCC units depending on whether a CAA section 111(d) plan has been submitted (or a federal plan promulgated). On the one hand, a CAA section 111(d) plan may not necessarily impose obligations on a particular unit. On the other hand, such a plan may impose significant obligations on a particular source, and if that source modifies, it may not be as well positioned to implement additional controls. A state, in developing a CAA section 111(d) plan, may choose to confer with its sources to determine whether any expect to modify, and, if any do, to take that into account in developing the state plan.
For affected modified natural gas-fired stationary combustion turbines, this action proposes standards of performance that are based on efficient NGCC technology as the BSER. The emission limits proposed for these
In the companion rulemaking proposing emission guidelines under CAA section 111(d) for CO
The EPA also solicits comment on an optional alternative method for calculating the emission limit that would be applicable to an affected modified natural gas-fired stationary combustion turbine after that unit becomes subject to a CAA section 111(d) plan. The EPA specifically seeks comment on the option of allowing the affected source to meet a unit-specific emission limit that is determined by the CAA section 111(b) implementing authority from an assessment to identify energy efficiency improvement opportunities for the affected source.
Reconstructed fossil fuel-fired boilers and IGCC units with a heat input rating that is greater than 2,000 MMBtu/h would be required to meet a standard of 1,900 lb CO
Reconstructed natural gas-fired stationary combustion turbines with a heat input rating greater than 850 MMBtu/h would be required to meet a standard of 1,000 lb CO
While the EPA is proposing these standards of performance, we are also taking comment on a range of potential emission limits. Specifically, we solicit comment on the following emission limit ranges:
(1) For reconstructed fossil fuel-fired boilers and IGCC units with a heat input rating that is greater than 2,000 MMBtu/h, a range of 1,700-2,100 lb CO
(2) for reconstructed fossil fuel-fired boilers and IGCC units with a heat input rating of 2,000 MMBtu/h or less, a range of 1,900-2,300 lb CO
(3) for reconstructed stationary combustion turbines with a heat input rating greater than 850 MMBtu/h, a range of 950-1,100 lb CO
(4) for reconstructed stationary combustion turbines with a heat input rating of 850 MMBtu/h or less, a range of 1,000-1,200 lb CO
We also solicit comment on whether: (1) The standards for utility boilers and IGCC units should be subcategorized by primary fuel type, (2) the small utility boiler and IGCC unit subcategory should be limited to utility boilers so that all IGCC units would be in the large subcategory regardless of size, or if there are sufficient alternate compliance technologies (e.g., co-firing natural gas) that the small unit subcategory is unnecessary and should be eliminated so that those sources would be required to meet the same emission standard as large utility boilers and IGCC units, and (3) an annual short-term performance test should be required for stationary combustion turbines in addition to the 12-operating-month rolling average standard. Requiring an initial and annual short term compliance test that is numerically more stringent than the 12-operating-month standard for modified and reconstructed stationary combustion turbines would insure that efficient stationary combustion turbines are installed and properly maintained. The less stringent 12-month rolling average standard would be set at a level that would account for operating conditions where the emission rate is higher than design conditions.
We are proposing standards for modified and reconstructed units as net output emission rates. We are also requesting comment on using either gross output standards or adjusted gross output based standards in the final rule.
We are proposing the standards in this rule apply at all times, including during periods of startup and shutdown. This section provides a summary of the requirements.
Consistent with
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as “any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operation are not malfunctions” (40 CFR 60.2). The EPA has determined that CAA section 111 does not require that emissions that occur during periods of malfunction be
Further, accounting for malfunctions in setting emission standards would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable.
In the event that a source fails to comply with the applicable CAA section 111 standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as undertake root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 111 standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 60.2 (containing the definition of malfunction).
Further, to the extent the EPA files an enforcement action against a source for violation of an emission standard, the source can raise any and all defenses in that enforcement action and at federal district court will determine what, if any, relief is appropriate. The same is true for citizen enforcement actions. Similarly, the presiding officer in an administrative proceeding can consider any defense raised and determine whether administrative penalties are appropriate.
In several prior rules, the EPA had included an affirmative defense to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, in ensuring adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Although the EPA recognized that its case-by-case enforcement discretion provides sufficient flexibility in these circumstances, it included the affirmative defense to provide a more formalized approach and more regulatory clarity.
We are proposing the same monitoring requirements for modified and reconstructed sources as were proposed for newly constructed sources in the January 2014 proposal. This section provides a summary of the requirements. For additional detail, see 79 FR 1450 and 1451.
Today's proposed rule would require owners or operators of EGUs that combust solid fuel to install, certify, maintain, and operate continuous emission monitoring systems (CEMS) to
The proposed rule would allow owners or operators of EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an alternative to CEMS and to calculate the hourly CO
In addition to requiring monitoring of the CO
The proposed rule would require EGU owners or operators to prepare and submit a monitoring plan that includes both electronic and hard copy components, in accordance with 40 CFR 75.53(g) and (h). Further, all monitoring systems used to determine the CO
The proposed rule would require only those operating hours in which valid data are collected and recorded for all of the parameters in the CO
Certain variations from and additions to the basic Part 75 monitoring would be required and are detailed in the January 2014 proposal (
Special compliance provisions for units with common stack or multiple stack configurations, consistent with section 60.13(g), would be required and are detailed in the January 2014 proposal (see 79 FR 1451).
The proposed rule would require 95 percent of the operating hours in each compliance period (including the compliance periods for the intermediate emission limits) to be valid hours, i.e., operating hours in which quality-assured data are collected and recorded for all of the parameters used to calculate CO
We are proposing two additional amendments to the monitoring requirements. First, we are proposing that measurements of electricity output (both gross and net) be measured using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. Second, we are proposing that hours with no gross generation or where the gross generation is less than the auxiliary loads be reported as zero instead of a negative value.
Steam is the most common type of useful thermal output for NSPS purposes. The amount of useful energy flowing in a steam header is measured with the following components: a flow meter (to determine the volumetric flow rate of steam in cubic meters per hour or the mass flow rate in kilograms per hour), a thermocouple or resistance temperature detector (to determine the temperature of the steam), and an electromechanical transmitter (to determine the pressure of the steam). The accuracy of the measurement of useful thermal energy calculation is the product of the accuracies of the flow, temperature, and pressure measurements. The January 2014 proposal includes requirements for the measurement of useful thermal output from CHP systems, but does not include associated specifications for quality assurance of the underlying flow, temperature, and pressure measurements. The EPA is considering and soliciting comment on requiring that manufacturers' maintenance recommendations be followed and include, at a minimum, annual inspection and calibration requirements for the flow meters, thermocouples or resistance temperature detectors (RTDs), and electromechanical transmitters used to acquire the steam flow rates and properties integral to calculation of useful thermal output.
The EPA is soliciting information on: (1) The technologies that are appropriate for continuous monitoring of useful thermal output, and (2) whether the EPA should specify the technologies to be used. For example, should technology choices be limited to ultrasonic, coriolis, averaging pitot tube with 2 differential pressure cells, or shedding vortex since they appear to be the most accurate? The EPA is also soliciting information on the costs of operating these systems, including ongoing maintenance, calibration intervals, and other quality assurance costs. Finally, with regard to the quality assurance requirements for continuous monitoring of useful thermal output, the EPA is soliciting comment on the appropriate ASTM, ANSI, or ASME standards (e.g., ASME PTC 4-2013, ASME PTC 19.5-2004 and ASME MFC-6-2013) that should be incorporated by reference into the final standards of performance. This would be an alternative to specifying technologies in order to ensure monitoring data are of sufficient quality for demonstrating compliance with the proposed efficiency standards.
We are proposing the same emissions performance testing requirements for modified and reconstructed sources as were proposed for newly constructed sources in the January 2014 proposal. This section provides a summary of the requirements. For additional detail, see 79 FR 1451.
In accordance with section 75.64(a), the proposed rule would require an EGU owner or operator to begin reporting emissions data when monitoring system certification is completed or when the 180-day window in section 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). The initial performance test would consist of the first 12-operating-months of data, starting with the month in which emissions are first required to be reported. The initial 12-operating-month compliance period would begin with the first month of the first calendar year of EGU operation in which the facility exceeds the capacity factor applicability threshold.
The traditional 3-run performance tests (i.e., stack tests) described in section 60.8 would not be required for this rule. Following the initial compliance determination, the emission standard would be met on a 12-operating-month rolling average basis.
We are proposing the same continuous compliance requirements for modified and reconstructed sources as were proposed for newly constructed sources in the January 2014 proposal.
Today's proposed rule specifies that compliance with the mass emissions rate limits would be determined on a 12-operating-month rolling average basis, updated after each new operating month. For each 12-operating-month compliance period, quality-assured data from the certified Part 75 monitoring systems would be used together with the gross output over that period of time to calculate the average CO
The proposed rule specifies that the first operating month included in the initial 12-operating-month compliance period would be the month in which reporting of emissions data is required to begin under section 75.64(a), i.e., either the month in which monitoring system certification is completed or the month in which the 180-day window allotted to finish certification testing expires (whichever month is earlier).
We are proposing that initial compliance with the applicable emissions limit in kg/MWh be calculated by dividing the sum of the hourly CO
We are proposing the same notification, recordkeeping and reporting requirements for modified and reconstructed sources as were proposed for newly constructed sources in the January 2014 proposal. This section provides a summary of the requirements. For additional detail, see 79 FR 1451 and 1452.
Today's proposed rule would require an EGU owner or operator to comply with the applicable notification requirements in sections 60.7(a)(1) and (a)(3), section 60.19 and section 75.61. The proposed rule would also require the applicable recordkeeping requirements in subpart F of Part 75 to be met. For EGUs using CEMS, the data elements that would be recorded include, among others, hourly CO
The proposed rule would require EGU owners or operators to keep records of the calculations performed to determine the total CO
The proposed rule would require all affected EGU owners/operators to submit quarterly electronic emissions reports in accordance with subpart G of Part 75. The proposed rule would require these reports to be submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. Except for a few EGUs that may be exempt from the Acid Rain Program (e.g., oil-fired units), this is not a new reporting requirement. Sources subject to the Acid Rain Program are already required to report the hourly CO
Additionally, in the proposed rule and as part of an Agency-wide effort to streamline and facilitate the reporting of environmental data, the rule would require that quarterly electronic “excess emissions” reports be submitted using ECMPS, within 30 days after the end of each quarter. Reporting the percentage of valid CO
In the January 2014 proposal, the EPA proposed that, in order to regulate GHG from newly constructed fossil fuel-fired EGUs, the EPA needed a rational basis, but that CAA section 111 did not require an endangerment finding. The EPA further proposed that even if CAA section 111 did require such a finding, the EPA's rational basis would qualify as one. The EPA expects to finalize the January 2014 proposal by the time that it finalizes this proposed rulemaking for affected modified and reconstructed fossil fuel-fired EGUs, and in that event, the EPA would not be required to further address the rational basis or endangerment finding in this rulemaking.
However, because this rulemaking is a separate action from the January 2014 proposal, the EPA is making the same proposal—that the EPA has a rational basis for this rulemaking, and that no endangerment finding is required, but that if one is, the EPA's rational basis would qualify as one—which it made in the January 2014 proposal.
This proposal addresses the same two source categories—fossil fuel-fired steam generating units (utility boilers and IGCC units) and natural gas-fired stationary combustion turbines—that were addressed by the January 2014 proposal. In the January 2014 proposal, the EPA included a proposal and co-proposal for the treatment of the two affected source categories, and for how the regulatory requirements applicable to these source categories would be codified in 40 CFR part 60. Specifically, the EPA proposed to create subcategories within each category, and to codify the regulatory requirements for each subcategory in 40 CFR part 60, subparts Da and KKKK, respectively. In addition, the EPA co-proposed to combine the two categories for purposes of regulating the CO
As noted, the EPA expects to finalize the January 2014 proposal by the time that it finalizes this proposed rulemaking for modified and reconstructed fossil fuel-fired EGUs. It is the EPA's intent that the approach for categorization and codification will be the same in the final action for this proposal as is finalized for the January 2014 proposal. However, because this rulemaking is a separate action from the January 2014 proposal, the EPA is making the same proposal and co-proposal with regard to categories and codification for modified and reconstructed sources that it made with regard to new construction sources in the January 2014 proposal. That is, the EPA proposes to create subcategories within each category and to codify the regulatory requirements in 40 CFR part 60, subparts Da and KKKK, respectively; and in addition, the EPA co-proposes to combine the two categories for purposes of regulating CO
The rationale for several of the proposed applicability requirements for modified and reconstructed sources is the same as that in the January 2014 proposal. This section provides a summary of the rationale for these requirements along with rationale for differences with the applicability included in the January 2014 proposal. In addition, we are soliciting comment on multiple alternative approaches to the applicability criteria.
The following four proposed applicability criteria are consistent with the January 2014 proposal. First, this proposal includes within the definition of a utility boiler, IGCC unit, and stationary combustion turbine that is subject to the proposed requirements, any integrated device that provides electricity or useful thermal output to the boiler, the stationary combustion turbine or to power auxiliary equipment. The rationale behind including integrated equipment recognizes that the integrated equipment may be a type of combustion unit that emits GHGs, and that it is important to assure that those GHG emissions are included as part of the overall GHG emissions from the affected source. Also consistent with the January 2014 proposal, we are considering including in the definition of the affected facility co-located non-emitting energy generation equipment included in the facility operating permit but that is not integrated into the operation of the affected facility.
Second, we are also proposing a different definition of potential electric output from the current definition that determines the potential electric output (in MWh on an annual basis) considering only the design heat input capacity of the facility and does not account for efficiency. It assumes a 33 percent net electric efficiency, regardless of the actual efficiency of the facility. Therefore, we are proposing a definition of potential electric output that allows the source the option of calculating its potential electric output on the basis of its actual design electric output efficiency on a net output basis, as an alternative to the default one-third value.
Third, we are proposing to apply the one-third sales criterion on a rolling 3-year basis instead of an annual basis for stationary combustion turbines for multiple reasons. First, extending the period to 3 years would ensure that the CO
Finally, we propose that if CHP facilities meet the general applicability criteria they should be subject to the same requirements as electric-only generators. However, one potential issue that we have identified is inequitable applicability to third-party CHP developers compared to CHP facilities owned by the facility using the thermal output from the CHP facility. We are therefore proposing to add “of the thermal host facility or facilities” to the definition of net-electric output for qualifying CHP facilities (i.e., the clause would read, “the gross electric sales to the utility power distribution system minus purchased power
The rationale for following applicability criteria is different from the January 2014 proposal. To clarify that existing boiler and IGCC facilities would continue to be included in CAA section 111(d) state programs regardless of their actual electric sales or fossil fuel use, we are deleting the criteria to be considered an EGU. These criteria include that the facility must (1) actually sell one-third of their potential electric output and 219,000 MWh on an annual basis and (2) the applicability exemption for facilities, than burn fossil fuel for 10 percent or less of the heat input during a 3-year rolling average period. The sales criteria exemption was intended to exempt low capacity factor facilities since they would have additional difficulties meeting the standards in the January 2014 proposal. However, the proposed standards for boilers and IGCC facilities in this rulemaking are less stringent and are achievable by low capacity factor facilities, so the applicability exemption would not be applicable. The low fossil use exemption was designed to exempt facilities that are capable of combusting fossil fuel, but burn primarily non fossil fuels. These facilities (e.g., wood-fired EGUs) typically are inherently less efficient than fossil fuel-fired EGUs, and we are soliciting comment on if we should subcategorize boilers and IGCC facilities where fossil fuel consists of 10 percent or less of the heat input during. In the event we establish a subcategory, should the heat input be determined on an annual or 3-year rolling period and should the standard be an alternate numerical limit or “no emission standard.”
In the January 2014 proposal, we also solicit comment on various issues concerning, and different approaches to, the applicability requirements for steam generating units and combustion turbines.
In the January 2014 proposal, we proposed a dual electric sales applicability criterion for stationary combustion turbines of 219,000 MWh and 33 percent sales of potential electric output on a 3-year rolling average basis. In addition, we specifically solicited comment on a range of 20 to 40 percent sales of potential electric output. However, the dual electric sales applicability could potentially result in
We are also soliciting comment on whether the percent sales of potential electric output is sufficient to account for the potential increased use of simple cycle combustion turbines due to the expected increased percentage of electricity generated from renewable generation in the future. Due to the intermittent nature of some renewable technologies, such as wind and solar, the electric grid must be balanced by using some type of quick response backup generation or rapid reductions in load. The EPA is soliciting comment on the extent to which simple cycle combustion turbines will be used to support additional renewable generation. We also solicit comment on the ability, relative costs and overall GHG emissions of energy storage systems (e.g., utility battery stations or flywheels) and on demand response programs to balance demand and generation from renewable electricity generation.
In addition, some of the initial feedback we received in public comments
The EPA is soliciting comment on whether a separate standard should be established for load-following (i.e., intermediate capacity factor) NGCC EGUs. The more stringent standard would apply only during periods of high annual capacity factors and a less stringent standard would apply during periods of intermediate load (e.g., when electric sales are between 33 to 60 percent of the potential electric output). This approach addresses two potential issues with the standards in the January 2014 proposal. First, certain NGCC units are designed to be highly efficient when operated as load-following units, but these design characteristics reduce the efficiency at base load. Conversely, the NGCC units with the highest base load design efficiencies are not necessarily as efficient as NGCC designed and intended to be used as load-following EGUs. Therefore, a full-load efficiency performance test would not necessarily result in the lowest CO
We are requesting comment on a full range of alternatives for low capacity factor stationary combustion turbines and/or simple cycle combustion turbines to the general applicability thresholds we proposed in the January 2014 proposal. This includes soliciting comment on whether we should: Establish a separate numerical limit for low capacity factor stationary combustion turbines and/or simple cycle combustion turbines; exempt all such units; set a higher capacity factor threshold applicable to all simple cycle turbines; establish a variable capacity
Consistent with the January 2014 proposal, the EPA is proposing the size distinction between large and small combustion turbines be a base load heat input rating of the combustion turbine engine of 850 MMBtu/h. As explained in the January 2014 proposal, this distinction is consistent with the criteria pollutant NSPS for stationary combustion turbines, which was based on the largest aeroderivative turbine design available at the time. However, incremental adjustments have been made to aeroderivative designs and the base load rating of the largest aeroderivative turbines now exceeds 850 MMBtu/h. The EPA is soliciting comment on increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs or to 1,000 MMBtu/h to account for future incremental increases in base load ratings. Alternately, the EPA is soliciting comment on increasing the size distinction to between 1,300 to 1,800 MMBtu/h. There are currently no combined cycle combustion turbines offered with turbine engine base load rating between those sizes.
In this section, we explain our rationale for emission standards for reconstructed fossil fuel-fired utility boiler and IGCC units, which are based on our proposal that the most efficient generating technology is the BSER for these types of units.
CAA section 111(b)(1)(B) authorizes the EPA to promulgate “standards of performance” for new sources, including modified and reconstructed sources. The CAA directs that standards of performance must consist of emission limits that are based on the “best system of emission reduction . . . adequately demonstrated,” taking into account cost and other factors. In this manner, CAA section 111 provides that the EPA's central task is to identify the BSER.
Over a 40-year period, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit or Court) has issued a number of decisions interpreting this CAA provision, including its component elements.
• The system of emission reduction must be technically feasible.
• The EPA must consider the amount of emissions reductions that the system would generate.
• The costs of the system must be reasonable. The EPA may consider the costs on the source level, the industry-wide level, and, at least in the case of the power sector, on the national level in terms of the overall costs of electricity and the impact on the national economy over time.
• The EPA must also consider that CAA section 111 is designed to promote the deployment, development and implementation of technology.
Other considerations are also important, including that the EPA must also consider energy impacts, and, as with costs, may consider them on the source level and on the nationwide structure of the power sector over time. Importantly, the EPA has discretion to weigh these various considerations, may determine that some merit greater weight than others, and may vary the weighting depending on the source category. The EPA discussed the CAA requirements and Court interpretations of the BSER at length in the January 2104 proposal, 79 FR 1462 through 1467, and incorporates by reference that discussion in this rulemaking.
It should be noted at the outset that the EPA determined that reconstructions are a type of construction, and therefore subject to CAA section 111(b), as part of the 1975 framework regulations, and the EPA is not re-opening that determination.
The EPA evaluated seven different control technology configurations as potentially representing the BSER for reconstructed fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) hybrid power plants (5) reductions in generation associated with dispatch changes, renewable generation, and
We discuss each of these alternatives below, and explain why we propose that for reconstructed fossil fuel-fired boiler and IGCC EGUs the most efficient generating technology qualifies as the BSER.
We considered the implementation of partial CCS as the BSER at affected reconstructed utility boilers and IGCC units. In the January 2014 proposal (79 FR 1430), the EPA found that, for new units, partial CCS has been adequately demonstrated and is technically feasible; it can be implemented at costs that are not unreasonable; it provides meaningful emission reductions; its implementation will serve to promote further development and deployment of the technology; and it would not have a significant impact on nationwide energy prices. The EPA also noted in the January 2014 proposal that most of the relatively few new projects that are in the development phase are already planning to implement CCS, so that partial CCS was consistent with current industry trends.
Partial CCS has been demonstrated at some existing EGUs. It has been demonstrated at a large pilot scale (e.g., 20 MW or greater) at two facilities: At Southern Company's Plant Barry and at AEP's Mountaineer Power Plant. A full scale, 110 MW project is currently being retrofitted at SaskPower's Boundary Dam coal-fired EGU in Canada and is expected to begin operation in 2014. Another large scale retrofit project (240 MW) is in advanced stages of project development at NRG Energy's WA Parish facility. There are also a number of smaller examples of CCS retrofits on coal-fired power plants.
However, the EPA does not, at present, have sufficient information about costs to propose that partial CCS is the BSER for reconstructed utility boilers and IGCC units. Utility boilers are numerous and diverse in size and configuration, and the EPA does not have sufficient information about the range of specific configurations that would be necessary to estimate the cost of partial CCS, on either a source-specific basis or an industry-wide basis. In particular, retrofitting a plant with partial CCS would entail integrating the carbon capture equipment with the affected unit's steam cycle (or with an external source of steam or heat) in order to release the captured CO
Therefore, the EPA does not propose to find that partial CCS is the BSER for CO
While conversion to or co-firing with natural gas in a utility boiler is a technically feasible option to reduce CO
However, we specifically solicit comment on whether natural gas reburning (NGR) and/or similar technologies
The EPA also requests comment on whether there are other factors or technologies related to co-firing that reduce its cost, and whether for these or other reasons, co-firing should be considered as BSER for reconstructed fossil fuel-fired electric utility steam generating units.
CHP, also known as cogeneration, is the simultaneous production of electricity and/or mechanical energy and useful thermal output from a single fuel. CHP requires less fuel to produce a given energy output, and because less fuel is burned to produce each unit of energy output, CHP reduces air pollution and greenhouse gas emissions. CHP has lower emission rates and can be more economic than separate electric and thermal generation. However, not all potentially modified and reconstructed utility boilers and IGCC units are located close enough to thermal hosts to economically or efficiently use the recovered thermal energy. Therefore, we are not proposing to find that CHP is the BSER for reconstructed utility boilers and IGCC units or stationary combustion turbines.
Hybrid power plants combine two or more forms of energy input into a single facility with an integrated mix of complementary generation methods. While there are multiple types of hybrid power plants, the most relevant type for this proposal is the integration of solar energy (e.g., concentrating solar thermal with or without photovoltaic generation) with a fossil fuel-fired EGU.
Our understanding is that one of the benefits of hybrid fossil EGUs is decreased incremental cost of the non-emitting (e.g., solar thermal) generated electricity due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, etc.) already included at the fossil fuel-fired EGU, as well as improvement of the electrical generation efficiency of the non-emitting generation. For example, solar thermal often produces steam at relatively low temperatures and pressures and the conversion efficiency of the thermal energy in the steam to electricity is relatively low. In a hybrid power plant, the lower quality steam is heated to higher temperatures and pressures in the boiler (or HRSG) prior to expansion in the steam turbine, where it produces electricity. Upgrading the relatively low grade steam produced by the solar thermal facility improves the relative conversion efficiencies of the solar thermal to electricity process. The primary incremental costs of the non-emitting solar thermal generation in a hybrid power plant is the costs of the mirrors, additional piping, and a steam turbine that is 10 to 20 percent larger than a comparable fossil only EGU to accommodate the additional steam load during sunny hours.
We specifically solicit comment on an alternate, but similar, approach for modified and reconstructed fossil fuel-fired EGUs to integrate lower emitting generation. The recovered thermal energy from natural gas-fired combustion turbines, fuel cells, or other combustion technology could be used to reheat or preheat boiler feed water (minimizing the steam that is otherwise extracted from the steam turbine), preheat makeup water and combustion air, produce steam for use in the steam turbine or to power the boiler feed pumps, or use the exhaust directly in the boiler to generate steam. In theory, this could lower generation costs as well the GHG emissions rate for a coal-fired EGU. However, at this time we do not have sufficient information on the costs or technical feasibility of this approach to include it as the BSER for reconstructed fossil fuel-fired utility boilers.
In the companion proposal in today's
1. Lowering the carbon intensity of generation at individual affected EGUs (e.g., through heat rate improvements);
2. Reducing emissions of the most carbon-intensive affected EGUs to the extent that this can be accomplished cost-effectively by shifting generation to less carbon-intensive existing NGCC units, including NGCC units that are under construction;
3. Reducing emissions of carbon-emitting EGUs to the extent that this can be accomplished cost-effectively by expanding the amount of new, lower (or no) carbon-intensity generation; and,
4. Reducing emissions of carbon-emitting EGUs to the extent that this can be accomplished cost-effectively by increasing demand-side energy efficiency.
In this rulemaking, we are, in effect, utilizing building block one—lowering the carbon intensity of generation at individual affected EGUs through heat rate improvements—as part of the BSER determination for modified units, but we are not proposing that building blocks two, three, or four are components of the BSER determination. We solicit comment on whether building blocks two, three and four would be appropriate in light of the fact that, unlike the CAA section 111(d) emission guidelines proposal, which will result in state plans that cover all existing sources, this proposal will result in a federal rule that covers only those sources that modify or reconstruct. We note that it is not possible in advance to determine which sources will do so. We solicit comment on any additional considerations that the EPA should take into account in the applicability of building blocks two, three and four in the BSER determination.
We also considered whether the proposed emission limit for reconstructed fossil fuel-fired utility boilers and IGCC units should be based on the performance of the most efficient generation technology available, which we believe is a supercritical pulverized coal (SCPC) or supercritical circulating fluidized bed (CFB) boiler for large sources, and subcritical for small sources. We propose to find that these technologies meet the criteria for the BSER.
The use of supercritical steam conditions has been demonstrated by many facilities since the 1960s for both large and small EGUs. In fact, the world's first commercial supercritical pressure EGU was the 125 MW Philo Unit 6 that commenced operation in 1957. Currently commercially available materials capable of tolerating steam conditions of 30 megapascal (MPa) (4,350 psi) and 605 °C (1,120 °F) have been demonstrated at coal-fired EGUs. In addition, even though the majority of recently constructed coal-fired EGUs use a single steam reheat cycle, the use of a dual steam reheat cycle has been demonstrated by multiple facilities as technically feasible. For a facility to be considered reconstructed for NSPS purposes, the boiler itself would have to be substantially refurbished. As part of a reconstruction, an owner/operator would be able to replace the steam tubing and other necessary equipment to allow the use of the best demonstrated steam cycle. Therefore, this option is technically feasible.
It should be noted that this approach identifies as the BSER changes in production technology that would result in fewer emissions, and not add-on technology that would control emissions. The kraft pulp mill NSPS (40 CFR part 60, subpart BB) is an example in which different equipment design (rather than add-on control) is the BSER for a modification or reconstruction.
The U.S. Department of Energy National Energy Technology Laboratory (DOE/NETL) has estimated that a new SCPC boiler using subbituminous coal would emit 7 percent less CO
While the percent reduction in CO
DOE/NETL has estimated, based on the levelized cost of electricity (LCOE), that the capital costs of a SCPC EGU are approximately 3 percent more than a comparable subcritical EGU. In fact, the reduced fuel costs are significant enough that the overall cost to generate electricity is actually lower for a SCPC EGU compared to a subcritical EGU. Therefore, the emission reductions are considered cost effective for larger EGUs.
For smaller boilers, less than approximately 200 MW, it is the understanding of the EPA that manufacturers of steam turbines do not currently offer turbines that have been thermodynamically optimized to use supercritical steam conditions. Instead, for smaller applications, they would typically adapt their larger turbines for the application. The resulting designs have a higher cost premium than larger supercritical steam turbines and do not take full advantage of the potential efficiency improvements and the benefits of using a supercritical steam cycle are reduced. Therefore, for smaller reconstructed EGUs the EPA has determined that the BSER is the use of highest available subcritical steam conditions. The maximum viable subcritical steam parameters are 21 MPa (3,000 psi) and 570 °C (1,060 °F). The EPA specifically solicits comment on the efficiency benefits and the costs of using supercritical steam conditions for smaller EGU designs. Modern materials are widely available that can tolerate the maximum subcritical steam parameters. Therefore, we anticipate the incremental cost of increasing steam parameters within subcritical conditions is low. We solicit comment on these costs.
Designating the most efficient generation technology as the BSER for reconstructed fossil fuel-fired utility boilers and IGCC units will not have significant impacts on nationwide electricity prices. The reason is that the additional costs of the use of efficient generation will, on a nationwide basis, be small because few reconstructed coal-fired projects are expected and because at least some of these reconstructions can be expected to incorporate the most efficient generation technology even in the absence of a standard.
For the same reason, designation of the most efficient generation technology as the BSER for reconstructed fossil fuel-fired utility boilers and IGCC units will not have adverse effects on the structure of the power sector, will not impact fuel diversity, and will not have adverse effects on the supply of electricity.
As noted above, the case law makes clear that the EPA is to consider the effect of its selection of BSER on technological innovation or development, but that the EPA also has the authority to weigh this factor along with the other ones. When it comes to the selection of the BSER, the EPA recognizes that reconstructed sources face inherent constraints that newly constructed greenfield sources do not; as a result, reconstructed sources present different, and in some ways more limited, opportunities for technological innovation or development. In this case, identifying the most efficient generation technology as the BSER promotes the further extension of that technology throughout the industry.
While some of the other options that the EPA considered in determining the BSER for reconstructed utility boilers and IGCC units would have led to greater opportunities for technology advancement, for the reasons discussed above, those other options did not meet other criteria. While the proposed standard is based on the use of the best available steam cycle, other energy efficiency measures will likely be developed and used (improved economizers, etc.) and these technologies will be transferrable to other EGUs.
The EPA also considered whether a combination of best operating practices and equipment upgrades would qualify as the BSER for a reconstruction. These measures are discussed in greater detail in Section VII of this preamble. A reconstruction, because it occurs only when an owner/operator spends more than 50 percent of the cost of a replacement unit, generally entails fundamental decisions about what type of unit to rebuild. For example, one reconstruction occurred following an explosion at the boiler and resulted in a rebuild of the entire unit including both the boiler and the accompanying steam turbine.
Because a reconstruction generally entails rebuilding the unit, operating practices and equipment upgrades are not applicable as BSER. Those entail smaller scale changes to the unit that may be expected to be rebuilt anyway. In addition, the emission reductions that could be achieved through best operating practices and equipment upgrades are smaller than the most efficient generation technology.
Once the EPA has determined that a particular system or technology represents BSER, the EPA must establish an emission standard based on
We are also soliciting comment on whether the emission limit may be more appropriately set at a different level. Based on the rationale included in the Technical Support Document (TSD),
We are not currently considering a standard more stringent than 1,700 lb CO
We are not currently considering a standard less stringent than 2,100 lb CO
The EPA is proposing that sources would be required to meet the proposed standards on a 12 operating-month rolling basis. The proposed compliance period requirements and rationale are the same as in the January 2014 proposal. This section provides a summary of the rationale. For additional detail, see 79 FR 1481 and 1482.
The 12-operating-month averaging period being proposed is important because of the inherent variability in power plant GHG emissions rates. Establishing a shorter averaging period would necessitate establishing a standard to account for the conditions that result in the lowest efficiency and therefore the highest GHG emissions rate.
EGU efficiency has a significant impact on the source's GHG emission rate. EGU efficiency can vary from month to month throughout the year. For example, high ambient temperature can negatively impact the efficiency of combustion turbine engines and steam generating units. As a result, an averaging period shorter than 12 operating-months would require us to set a standard that could be achieved under these conditions. This standard could potentially be high enough that it would not be a meaningful constraint during other parts of the year. In addition, operation at low load conditions can also negatively impact efficiency. It is likely that for some short period of time an EGU will operate at an unusually low load. A short averaging period that accounts for this operation would again not produce a meaningful constraint for typical loads.
On the other hand, a 12-operating-month rolling average explicitly accounts for variable operating conditions, allows for a more protective standard and decreased compliance burden, allows EGUs to have and use a consistent basis for calculating compliance (i.e., ensuring that 12 operating months of data would be used to calculate compliance irrespective of the number of long-term outages), and simplifies compliance for state permitting authorities. The EPA proposes that it is not necessary to have a shorter averaging period for CO
In this section we explain our rationale for proposing, as the “best system of emission reduction . . . adequately demonstrated” for modified fossil fuel-fired utility boiler and IGCC EGUs, a combination of best operating practices and equipment upgrades.
We include in this discussion: (1) Our rationale for rejecting other alternatives as BSER, (2) a description of efficiency improvements achieved through a combination of best operating practices and equipment upgrades and our rationale for selecting it as BSER, and (3) our rationale for co-proposed alternative standards of performance based on this BSER (including varying the standard depending upon whether the affected source would be subject to a CAA section 111(d) plan (or promulgated federal plan) for CO
For the same reasons explained above for reconstructed fossil fuel-fired boiler and IGCC EGUs, the EPA is not proposing the following options to be BSER for modified fossil fuel-fired utility boiler and IGCC units: (1) The use of partial CCS, (2) conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) Hybrid Power Plants, and (5)
In this section, we evaluate two other options for BSER: (1) Efficiency improvements achieved through the use of the most efficient generation technology, and (2) efficiency improvements achieved through a combination of best operating practices and equipment upgrades.
We considered whether the BSER for modified fossil fuel-fired utility boilers and IGCC units should be based on the performance of the most efficient generation technology available, which we believe is a supercritical
Unlike in the case of reconstruction explained above, it is the understanding of the EPA that modifications do not typically involve the type of boiler rebuilding that would make this an option with reasonable cost. Consequently, the EPA does not propose to find that the use of the most efficient generation technology meets the criteria for the BSER for a uniform nationwide standard of performance.
The second option that EPA considered for modified fossil fuel-fired utility boilers and IGCC units is a combination of best operating practices and equipment upgrades. Best operating practices includes both operating the unit in the most efficient manner for a given operating condition and replacing worn components in a timely manner. Equipment upgrades involve replacing existing components with upgraded ones or a more extensive overhaul of major equipment (turbine or boiler). We propose to find that this option meets the criteria for BSER for these EGUs.
In addition, we are co-proposing two alternative standards of performance reflective of this BSER. In the first co-proposed alternative, all modified utility boilers and IGCC units will be required to meet a unit-specific emission standard. In the second co-proposed alternative, modified sources will be required to meet unit-specific emission limits that will depend on whether the affected unit undertakes the modification before it becomes subject to a CAA section 111(d) state plan (or promulgated federal plan), or after it becomes subject to such a plan. Each variation of the BSER meets the criteria, which we discuss next. We describe the variations in more detail in the section concerning the standards of performance, which follows the discussion of the criteria.
A wide range of studies have been performed evaluating the opportunity to improve the heat rate (or efficiency)
Many of the detailed engineering studies describe a wide range of opportunities to improve heat rate including improvements to the: (1) Materials handling equipment at the plant, (2) economizer, (3) boiler control systems, (4) soot blowers, (5) air heaters, (6) steam turbine, (7) feed water heaters, (8) condenser, (9) boiler feed pumps, (10) induced draft (ID) fans, (11) emission controls, and (12) water treatment systems.
As the studies show, these types of upgrades have been made at a wide range of power plants, demonstrating their technical feasibility.
This approach would achieve reasonable reductions in CO
The EPA reviewed the engineering studies available in the literature and selected the Sargent & Lundy 2009 study
The 2009 Sargent & Lundy study included an estimated range of heat rate improvement, and the associated range of capital cost for each heat rate improvement method, for units ranging in size from 200 MW to 900 MW. If the methods and unit sizes are combined, as though they were all applied on a single EGU, the range of Sargent & Lundy estimated Btu reductions (412 to 1,205 Btu) resulted in associated combined capital costs in the range of $40-150/kW. The wide ranges of estimated Btu reductions and capital costs are indicative of the wide range of real differences in the many details of site specific EGU designs, fuel types, age, size, ambient conditions, current physical condition, etc. The EPA's analysis, therefore, assumed $100/kW as a representative combined heat rate improvement capital cost to achieve whatever Btu reduction is possible at an average site.
The EPA heat rate improvement analysis resulted in the following summary conclusions:
• Some degree of heat rate improvement is already economic for high heat rate—high coal cost EGUs.
• If a fleet-wide average 6 percent heat rate is technically feasible, it would also be economic on the basis of fuel savings alone, before consideration of the value of the associated CO
• Even at a capital cost of $100/kW and an Integrated Planning Model (IPM) projected 2020 coal price of $2.62/MMBtu, the fleet-wide cost of CO
Based on this assessment, the EPA determines that the unit-specific emission limit based on historical best performance (which captures the good operating practice at the unit) coupled with an additional 2 percent reduction (which captures minimum opportunities for additional heat rate improvements from equipment and system upgrades) can be achieved at reasonable cost.
The EPA's modeling tools do not allow projection of any specific number of utility boilers and IGCC units that are expected to trigger the NSPS modification provision. As discussed below, however, the EPA believes there are likely to be few. Hence, a unit-specific standard of performance will not have significant impacts on nationwide electricity prices or on the structure of the nation's energy sector.
As noted previously, the case law makes clear that the EPA is to consider the effect of its selection of the BSER on technological innovation or development, but that the EPA also has the authority to weigh this factor, along with the various other factors. With the selection of emissions controls, modified sources face inherent constraints that newly constructed greenfield and even reconstructed sources do not; as a result, modified sources present different, and in some ways more limited, opportunities for technological innovation or development. In this case, the proposed standards promote technological development by promoting further development and market penetration of equipment upgrades and process changes that improve plant efficiency.
Once the EPA has determined that a particular system or technology represents BSER, the EPA must establish an emission standard based on that technology.
Because the existing fossil fuel-fired steam-generating boilers are numerous and diverse in size and configuration—and because the EPA has no way to predict which of those sources may modify—developing a single standard for all modified utility boilers or IGCC units is challenging. The EPA considered a sub-categorization approach, but, as is detailed in Chapter 2 of the TSD, “GHG Abatement Measures,” analysis of available data did not support a number of potential sub-categorization options—such as unit size, type or age—that intuitively seemed logical.
In this action, the EPA is co-proposing two alternative standards of performance for modified utility boilers and IGCC units. In the first co-proposed alternative, all modified sources would meet a unit-specific emission limit. In the second co-proposed alternative, the modified source would be required to meet a unit-specific emission limit that will depend on the timing of the modification.
For utility boilers or IGCC units undertaking modifications, the EPA is proposing that the BSER has two components: (1) That the source operates consistently with its own best demonstrated historical performance; and (2) that the source implements other available heat rate improvement measures including upgrading of some components of the unit. Specifically, for the first co-proposed alternative, a modified utility boiler or IGCC unit would be required to maintain an emission rate that equals the unit's best demonstrated annual performance during the years from 2002 to the year the modification occurs, multiplied by 98 percent (i.e., a 2 percent further reduction), but not to be more stringent than the emission limit that would be applicable to the source if it were a reconstructed source. Consistent with the heat rate improvement analysis in the CAA section 111(d) proposal, we selected 2002 to assure we captured the impacts of maintenance cycles and year to year natural variability in CO
As mentioned, the EPA is also co-proposing standards of performance that are dependent on the timing of the modification. Specifically, a source that modifies prior to becoming subject to a CAA section 111(d) plan would be required to meet an emission limit that is determined using the same methodology described in the first co-proposed alternative. The modified utility boiler or IGCC unit would be required to maintain an emission rate that equals the unit's best demonstrated annual performance during the years from 2002 to the year the modification occurs, multiplied by 98 percent (i.e., a 2 percent further reduction based on equipment upgrades), but not to be more stringent than the emission limit applicable to a corresponding reconstructed source. The EPA is proposing that units undertaking modifications after they become subject to a CAA section 111(d) plan would be required to meet a unit-specific emission limit that is determined by the CAA section 111(d) implementing authority from an assessment to identify energy efficiency improvement opportunities for the affected source. This standard is informed by the fact that, as we discuss in the Legal Memorandum,
The EPA also solicits comment on whether the period of best historical performance should be the years from
We are considering different standards applicable before and after a source becomes subject to a CAA section 111(d) plan because we are concerned that, as a result of implementation of state plans, the additional 2 percent efficiency improvement may be unachievable for a substantial number of sources that make efficiency improvements as part of a CAA section 111(d) plan. Specifically, we are concerned that where a state imposes efficiency improvements on a source, or where a source undertakes efficiency improvements to comply with the state plan, it will have already attained the maximum level of efficiency improvement that is achievable for that unit. As a result, the source would be unable to undertake additional improvements to meet the highest level of efficiency plus the additional 2 percent reduction (based on equipment upgrades) that we are considering. We recognize that in some states, CAA section 111(d) plans may require no or limited efficiency improvements on a specific unit. In such cases, we expect such a unit to be able to achieve the standard we are considering for sources that modify prior to becoming subject to a CAA section 111(d) plan. Accordingly, for such sources, we anticipate that the audit process that we are considering will result in an emission rate consistent with the highest level of efficiency plus 2 percent (based on equipment upgrades) that we are considering for sources that modify prior to becoming subject to a state plan.
For this co-proposal, the EPA is proposing that the date for determining whether a unit is subject to a CAA section 111(d) plan is the date that the plan is initially submitted to the EPA. Although a state's plan is still subject to the EPA's approval, we believe this represents a reasonable point to determine that a source is subject to a CAA section 111(d) plan, because at that point the operator would know what requirements the source would have to meet, and would have confirmation of the state's intention to submit that plan to meet the requirements of CAA section 111(d). We are also taking comment on a range of other dates including: June 30, 2016 (the original state plan submission deadline), the date that the state promulgates its rule, the date the EPA approves the rule, and January 1, 2020 (the proposed initial compliance date for state plans).
For a source modifying after a CAA section 111(d) plan becomes applicable, a unit-specific emission standard will be determined by the CAA section 111(d) implementing authority from the results of an energy efficiency audit to identify technically feasible heat rate improvement opportunities at the affected source.
An energy efficiency audit, or assessment, is an in-depth energy study identifying all energy conservation measures appropriate for a facility given its operating parameters. An energy audit is a process that involves a thorough examination of potential savings from energy efficiency improvements, pollution prevention, and productivity improvement. It leads to the reduction of emissions of pollutants through process changes and other efficiency modifications. Besides reducing operating and maintenance costs, improving energy efficiency results in decreased fuel use which results in a corresponding decrease in emissions. Such an energy assessment requirement is included in the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (40 CFR part 63, subpart DDDDD).
We propose that the energy assessment would include, at a minimum, the following elements:
1. A visual inspection of the facility to identify steam leaks or other sources of reduced efficiency;
2. a review of available engineering plans and facility operation and maintenance procedures and logs; and
3. a comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments.
We propose that the energy assessment be conducted by energy professionals or engineers that have expertise in evaluating energy systems. We specifically request comment on: (1) Whether energy assessor certification should be required; (2) if certification were required, what the basis of the certification should be; and (3) whether there are organizations that provide certification of specialists in evaluating energy systems. We propose that the CAA section 111(d) implementing authority will determine a unit-specific emission limit based on the results of the energy efficiency audit and we also request comment on: (1) Whether the rule should require implementation of identified energy efficiency improvements; and (2) if implementation were required, what the determining factor(s) for requiring the improvements should be. Finally, we request comment on: (1) Whether an energy efficiency audit recently completed (e.g., within 3 years of the modification) that meets or is amended to meet the rule's energy audit requirements can be used to satisfy the energy efficiency audit requirement and, in such instances, whether energy assessor approval and qualification requirements should be waived; and (2) whether facilities that operate under an energy management program compatible to ISO 50001
The EPA also seeks comment on whether, and under what circumstances, the energy audit methodology—i.e., determining the emission limit from the results of the energy audit—should be an option for sources that modify before becoming subject to a CAA section 111(d) plan. In particular, the EPA seeks comment on whether the audit methodology should be an option for all units that modify, prior to becoming subject to a CAA section 111(d) plan, or if it should be an option for sources that provide evidence that significant energy efficiency improvements were implemented after 2002 but before the modification.
The EPA is proposing that sources would be required to meet the proposed standards on a 12 operating-month rolling basis. The compliance period requirements and rationale being proposed for modified boilers and IGCC units are the same as the requirements and rationale being proposed for reconstructed utility boilers and IGCC units (see section VII.D. of this preamble), as well as the compliance period requirements and rationale in the January 2014 proposal. For additional detail, see 79 FR 1481 and 1482.
The EPA evaluated three different control technology configurations as potentially representing the “best system of emissions reductions . . .
We are not proposing to find that CCS technology is the BSER for reconstructed natural gas-fired stationary combustion turbines for the same reasons we are not proposing to find that CCS technology is the BSER for steam-generating units: an owner/operator of an existing source that is undertaking reconstruction has challenges not faced when building a new NGCC unit because the existing unit may be located at a site with space constraints that would make installation of CCS problematic. We do not have sufficient information about the universe of existing sources to be able to determine the costs of CCS, in light of these space constraints.
For the reasons explained below, we find NGCC technology to be BSER for reconstructed natural gas-fired stationary combustion turbines.
NGCC technology is widely used in the power sector today. There are hundreds of NGCCs in the U.S. and in other countries.
NGCC technology is the most efficient technology for natural-gas fired stationary combustion turbines. It has an emission rate that is approximately 25 percent lower than the most effective main alternative technology, which is the simple cycle combustion turbine.
NGCC technology is one of the lowest cost forms of baseload and intermediate load electricity generation. Even in the case of a simple cycle turbines that operates at a capacity factor of greater than one-third, the cost of replacement with a NGCC unit is likely to be cost effective based on consideration of fuel savings alone. In the proposal for newly constructed sources (79 FR 1459), we explained that at capacity factors of greater than 20 percent, the LCOE of a combined cycle unit would be less than the LCOE of a simple cycle turbine. Because the cost of adding a HRSG to a simple cycle turbine is less than the cost of building a full combined cycle unit, the same holds true with a comparison of replacing a simple cycle turbine and upgrading it to a combined cycle turbine. Furthermore, if the owner/operator of a simple cycle turbine wishes to make a modification, they could do so—without having to comply with the requirements of this proposal—by maintaining an average annual capacity factor of less than one-third. As we explained in the proposal, few simple cycle turbines operate at an annual capacity factor of greater than one-third. (79 FR 1459)
We recognize that because NGCC technology is already the state of the art technology, and is widely used, for natural gas stationary combustion turbines, identifying this technology as the BSER may not provide significant incentive for technology innovation. However, we are according less weight to this factor in this case because we consider this technology to be highly efficient and because the only more stringent alternative—CCS—is one that we are not proposing to identify as BSER, for reasons discussed above.
The use of high efficiency simple cycle aeroderivative turbines does not provide emission reductions when compared to the NGCC technology. According to the Annual Energy Outlook (AEO) 2013 emissions rate information, advanced simple cycle combustion turbines have a base load rating CO
The proposed standards of performance for reconstructed natural gas-fired stationary combustion turbines, which are based on BSER being efficient NGCC technology, are consistent with those that were proposed for newly constructed natural gas-fired stationary combustion turbine sources, as described in the January 2014 proposal (79 FR 1430). The EPA intends—when it takes final action on this proposal and on the January 2014 proposal for newly constructed sources, respectively—to finalize the same standards for newly constructed, modified and reconstructed natural gas-fired stationary combustion turbines. The EPA solicits comment on this approach and on any reasons why these sources should not have consistent standards.
In the January 2014 proposal, the EPA indicated that it had reviewed the CO
Consistent with the January 2014 proposal, the EPA proposes to subcategorize the turbines into the same two size-related subcategories currently in subpart KKKK for standards of performance for the combustion turbine criteria pollutants. These subcategories are based on whether the design heat input rate to the turbine engine is either 850 MMBtu/h or less, or greater than 850 MMBtu/h. We further propose to establish different standards of performance for these two subcategories.
This subcategorization has a basis in differences in several types of equipment used in the differently sized units, which affect the efficiency of the units. Because of these differences in equipment and inherent efficiencies of scale, the smaller capacity NGCC units (850 MMBtu/h and smaller) are less efficient than the larger units (larger than 850 MMBtu/h). We are proposing standards of performance of 1,000 lb CO
We believe that the analysis above with regards to reconstructed natural gas-fired stationary combustion turbines is also applicable to modified natural gas-fired stationary combustion
Because the performance of combined cycle technology has improved so significantly since 2000, we believe that upgrading to current technology is likely to be cost effective when one considers a combination of fuel savings, and performance benefits (the ability to start up the unit more quickly and operate more efficiently over a wider range of loads).
These modifications are likely to be made to return the unit to close to its original operating performance, would be consistent with the requirements of today's proposal, and are not likely to significantly increase the cost of the project.
These modifications would be made to upgrade the efficiency of the unit, are consistent with the requirements of today's proposal, and are not likely to significantly increase the cost of the project.
As was noted above—and in the proposal for newly constructed sources—when operating at higher capacity factors, the use of combined cycle technology instead of simple cycle technology pays for itself in fuel savings alone.
For these reasons, we find the use of NGCC technology to be BSER for modified natural gas-fired combustion turbines.
We propose that the same standards of performance described above for reconstructed natural gas-fired stationary combustion turbines are also appropriate for modified natural gas-fired stationary combustion turbines.
We are requesting comment on a range of 950 to 1,100 lb CO
For sources that are subject to a CAA section 111(d) plan, the EPA is also soliciting comment on whether the sources should be allowed to elect, as an alternative to the otherwise applicable numeric standard, to meet a unit-specific emission standard, determined by the CAA 111(d) implementing authority, based on implementation of identified energy efficiency improvement opportunities applicable to the source.
As explained in the RIA for this proposed rule, the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions that we are proposing today. Because the EPA is aware of a limited number of units that have notified the EPA of NSPS modifications in the past, we have conducted an illustrative analysis of the costs and benefits for a representative unit. Based on the analysis, which is presented in Chapter 9 of the RIA, the EPA expects that this proposed rule will result in potential CO
As explained immediately above, the EPA expects few modified or reconstructed EGUs in the period of analysis. Because there have been a limited number of units that have notified the EPA of NSPS modifications in the past, we have conducted an illustrative analysis of the impacts for a hypothetical unit that triggered the modification provision. For this illustrative example, we estimate CO
This proposed rule is not anticipated to have significant impacts on the supply, distribution, or use of energy. As previously stated, the EPA expects few reconstructed or modified EGUs in the period of analysis and the nationwide cost impacts to be minimal as a result.
The EPA believes this proposed rule will have minimal compliance costs associated with it, because, as previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Because the EPA is aware of a limited number of units that have notified the EPA of NSPS modifications in the past, we have conducted an illustrative analysis of the costs and benefits for a representative unit. Based on the analysis, which is presented in Chapter 9 of the RIA, the EPA estimates compliance costs, net of fuel savings, of $0.78 to $4.5 million (2011$) in 2025 for a hypothetical unit that triggered the modification provisions.
As previously explained, the special characteristics of GHGs make it important to take action to control the largest emissions categories without delay. Unlike most traditional air pollutants, GHGs persist in the atmosphere for time periods ranging from decades to millennia, depending on the gas. Fossil fuel-fired power plants emit more GHG emissions than any other stationary source category in the U.S.
This proposed rule would limit GHG emissions from modified fossil fuel-
As previously stated, the EPA anticipates few units will trigger the proposed modification or reconstruction provisions. For this reason, the proposed standards will result in minimal emission reductions, costs, or quantified benefits by 2025. There are no macroeconomic or employment impacts expected as a result of these proposed standards.
As previously stated, the EPA anticipates few units will trigger the proposed modification or reconstruction provisions. Because there have been a limited number of units that have notified the EPA of NSPS modifications in the past, we have conducted an illustrative analysis of the costs and benefits for a representative unit. Based on the analysis, which is presented in Chapter 9 of the RIA, the combined climate benefits from reductions in CO
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a “significant regulatory action” because it “raises novel legal or policy issues arising out of legal mandates.” Accordingly, the EPA submitted this action to the OMB for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to the OMB recommendations have been documented in the docket for this action. In addition, the EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in Chapter 9 of the Regulatory Impact Analysis for Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating Units.
As explained in the RIA for this proposed rule, in the period of analysis (through 2025) the EPA anticipates few sources will trigger either the modification or the reconstruction provisions proposed. Because there have been a few units that have notified the EPA of NSPS modifications in the past, we have conducted an illustrative analysis of the costs and benefits for a representative unit that is included in Chapter 9 of the RIA.
This proposed action is not expected to impose an information collection burden under the provisions of the
The EPA intends to codify the standards of performance in the same way for both this proposed action and the January 2014 proposal for newly constructed sources and is proposing the same recordkeeping and reporting requirements that were included in the January 2014 proposal.
Although, as stated above, the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions that we are proposing, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, it is likely that an EGU's energy metering equipment would need to be
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. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID number EPA-HQ-OAR-2013-0603. Submit any comments related to the ICR to the EPA and OMB. See
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small entities, small entity is defined as:
(1) A small business that is defined by the SBA's regulations at 13 CFR 121.201 (for the electric power generation industry, the small business size standard is an ultimate parent entity with less than 750 employees.);
(2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and
(3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities.
The EPA expects few modified utility boilers, IGCC units, or stationary combustion turbines in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
Because there have been a limited number of units that have notified the EPA of NSPS modifications in the past, the RIA for this proposed rule includes an illustrative analysis of the costs and benefits for a representative unit.
Based on the analysis, the EPA estimates that this proposed rule could result in CO
In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units (utility boilers and IGCC units) or stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility. Due to the limited data available on reconstructions, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this proposal in the unlikely case that a unit were to reconstruct. However, based on the low number of previous reconstructions and the BSER determination based on the most efficient available generating technology, we would expect this proposal to result in no significant CO
Nevertheless, the EPA is aware that there is substantial interest in the proposed rule among small entities (municipal and rural electric cooperatives). As summarized in section II.G. of this preamble, the EPA has conducted an unprecedented amount of stakeholder outreach. As part of that outreach, agency officials participated in many meetings with individual utilities as well as meetings with electric utility associations. Specifically, the EPA Administrator, Gina McCarthy, participated in separate meetings with both the National Rural Electric Cooperative Association (NRECA) and the American Public Power Association (APPA). The meetings brought together leaders of the rural cooperatives and public power utilities from across the country. The Administrator discussed and exchanged information on the unique challenges, in particular the financial structure, of NRECA and APPA member utilities. A detailed discussion of the stakeholder outreach is included in the preamble to the emission guidelines for existing affected electric utility generating units being proposed in a separate action.
In addition, as described in the RFA section of the preamble to the proposed standards of performance for GHG emissions from new EGUs (79 FR 1499 and 1500), the EPA conducted outreach to representatives of small entities while formulating the provisions of the proposed standards. Although only new EGUs would be affected by those proposed standards, the outreach regarded planned actions for newly constructed, reconstructed, modified and existing sources.
While formulating the provisions of this proposed rule, the EPA considered the input provided over the course of the stakeholder outreach. We invite comments on all aspects of this proposal
This proposed rule does not contain a federal mandate that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or the private sector in any one year. As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units (utility boilers and IGCC units) or stationary combustion turbines in the period of analysis. Accordingly, this proposed rule is not subject to the requirements of sections 202 or 205 of UMRA.
This proposed rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.
In light of the interest among governmental entities, the EPA initiated consultations with governmental entities while formulating the provisions of the proposed standards for newly constructed EGUs. This outreach regarded planned actions for newly constructed, reconstructed, modified and existing sources. As described in the UMRA discussion in the preamble to the proposed standards of performance for GHG emissions from newly constructed EGUs (79 FR 1500 and 1501), the EPA consulted with the following 10 national organizations representing state and local elected officials: (1) National Governors Association; (2) National Conference of State Legislatures; (3) Council of State Governments; (4) National League of Cities; (5) U.S. Conference of Mayors; (6) National Association of Counties; (7) International City/County Management Association; (8) National Association of Towns and Townships; (9) County Executives of America; and (10) Environmental Council of States. On February 26, 2014, the EPA re-engaged with those governmental entities to provide a pre-proposal update on the emission guidelines for existing EGUs and emission standards for modified and reconstructed EGUs.
While formulating the provisions of these proposed standards, the EPA also considered the input provided over the course of the extensive stakeholder outreach conducted by the EPA (see section II.G. of this preamble).
This proposed action does not have federalism implications. It would not have substantial direct effects 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, as specified in Executive Order 13132. This proposed action would not impose substantial direct compliance costs on state or local governments, nor would it preempt state law. Thus, Executive Order 13132 does not apply to this action.
However, as described in the Federalism discussion in the preamble to the proposed standards of performance for GHG emissions from newly constructed EGUs (79 FR 1501, January 8, 2014), the EPA consulted with state and local officials in the process of developing the proposed standards for newly constructed EGUs. This outreach regarded planned actions for newly constructed, reconstructed, modified and existing sources. The EPA engaged 10 national organizations representing state and local elected officials. The UMRA discussion in the preamble to the proposed standards of performance for GHG emissions from newly constructed EGUs (79 FR 1500 and 1501) includes a description of the consultation. In addition, on February 26, 2014, the EPA re-engaged with those governmental entities to provide a pre-proposal update on the emission guidelines for existing EGUs and emission standards for modified and reconstructed EGUs. While formulating the provisions of these proposed standards, the EPA also considered the input provided over the course of the extensive stakeholder outreach conducted by the EPA (see section II.G. of this preamble). In the spirit of Executive Order 13132 and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed action from state and local officials.
This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It would neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on owners and operators of reconstructed and modified EGUs. The EPA is aware of three coal-fired EGUs located in Indian country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that this proposal would only affect existing sources such as the three coal-fired EGUs located in Indian country, if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA's NSPS regulations. However, as previously stated the EPA expects few modified or reconstructed EGUs in the period of analysis. Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, the EPA conducted outreach to tribal environmental staff and offered consultation with tribal officials in developing this action. Because the EPA is aware of tribal interest in carbon pollution standards for the power sector, prior to proposal of GHG standards for newly constructed power plants, the EPA offered consultation with tribal officials early in the process of developing the proposed regulation to permit them to have meaningful and timely input into its development. The EPA's consultation regarded planned actions for newly constructed, reconstructed, modified, and existing sources. The Consultation and Coordination with Indian Tribal Governments discussion in the preamble to the proposed standards of performance for GHG emissions from newly constructed EGUs (79 FR 1501) includes a description of that consultation.
During development of this proposed regulation, consultation letters were sent to 584 tribal leaders. The letters provided information regarding the EPA's development of both the NSPS for modified and reconstructed EGUs and emission guidelines for existing EGUs and offered consultation. No tribes have requested consultation. Tribes were invited to participate in the national informational webinar held August 27, 2013, and to which tribes were invited. In addition, a consultation/outreach meeting was held on September 9, 2013, with tribal representatives from some of the 584 tribes. The EPA also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. In those teleconferences, the EPA provided background information on the GHG emission guidelines to be developed and a summary of issues being explored by the agency. Additional detail regarding this stakeholder outreach is included in the preamble to the emission guidelines for existing affected electric utility generating units being proposed in a separate action today. The EPA also held a series of listening sessions prior to proposal of GHG standards for newly constructed power plants. Tribes participated in a session on February 17, 2011, with the state
The EPA will also hold additional meetings with tribal environmental staff during the public comment period, to inform them of the content of this proposal, as well as offer further consultation with tribal officials where it is appropriate. We specifically solicit additional comment from tribal officials on this proposed rule.
The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it is based solely on technology performance.
This proposed action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. As previously stated, the EPA expects few reconstructed or modified EGUs in the period of analysis and impacts on emissions, costs or energy supply decisions for the affected electric utility industry to be minimal as a result.
Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs the EPA to use VCS in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs the EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable VCS.
This proposed rulemaking involves technical standards. The EPA proposes to use the following standards in this proposed rule: ASTM D388-12 (Standard Classification of Coals by Rank), ASTM D396-13c (Standard Specification for Fuel Oils), ASTM D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), ASTM D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and ANSI C12.20 (American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes). The EPA is proposing use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA.
The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards should be used in this action.
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S.
This proposed rule limits GHG emissions from modified and reconstructed fossil fuel-fired electric utility steam generating units (utility boilers and IGCC units) and stationary combustion turbines by establishing national emission standards for CO
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
The Environmental Protection Agency proposed rule amending 40 CFR parts 60, 70, 71, and 98, which was published at 79 FR 1430, January 8, 2014, proposed amendments to the regulatory text of 40 CFR part 60, subparts Da and KKKK, and, as an alternative to amending subparts Da and KKKK, to create a new subpart (40 CFR part 60, subpart TTTT) to include GHG standards for newly constructed EGUs. To facilitate understanding the amendments being proposed in this proposal, we are providing a Technical Support Document in the docket for this rulemaking in track changes that shows the proposed amendments considering the amendments proposed in the January 8, 2014,